ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010

OR

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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM
TO

Commission File Number 1-31447

______________________

CenterPoint Energy, Inc.

(Exact name of registrant as specified in its charter)

Texas

74-0694415

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

1111 Louisiana

Houston, Texas 77002

(Address and zip code of principal executive offices)

(713) 207-1111

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Name of each exchange on which registered

Common Stock, $0.01 par value and associated

rights to purchase preferred stock

New York Stock Exchange

Chicago Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
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No
o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
o
No
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Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
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No
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Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes
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No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of the registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer
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Accelerated filer
o

Non-accelerated filer
o

Smaller reporting company
o

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
o
No
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The aggregate market value of the voting stock held by non-affiliates of CenterPoint Energy, Inc. (CenterPoint Energy) was $5,507,110,378 as of June 30, 2010, using the definition of beneficial ownership contained in Rule 13d-3 promulgated pursuant to the Securities Exchange Act of 1934 and excluding shares held by directors and executive officers. As of February 15, 2011, CenterPoint Energy had 424,849,673 shares of Common Stock outstanding. Excluded from the number of shares of Common Stock outstanding are 166 shares held by CenterPoint Energy as treasury stock.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2011 Annual Meeting of Shareholders of CenterPoint Energy, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2010, are incorporated by reference in Item 10, Item 11, Item 12, Item 13 and Item 14 of Part III of this Form 10-K.

From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from those expressed or implied by these statements. You can generally identify our forward-looking statements by the words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “should,” “will” or other similar words.

We have based our forward-looking statements on our management’s beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements.

Some of the factors that could cause actual results to differ from those expressed or implied by our forward-looking statements are described under “Risk Factors” in Item 1A and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Certain Factors Affecting Future Earnings” and “ – Liquidity and Capital Resources – Other Factors That Could Affect Cash Requirements” in Item 7 of this report, which discussions are incorporated herein by reference.

You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement.

We are a public utility holding company whose indirect wholly owned subsidiaries include:

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CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes the city of Houston; and

Our reportable business segments are Electric Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations. From time to time, we consider the acquisition or the disposition of assets or businesses.

We make available free of charge on our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such reports with, or furnish them to, the Securities and Exchange Commission (SEC). Additionally, we make available free of charge on our Internet website:

the charters of the audit, compensation, finance, governance and strategic planning committees of our Board of Directors.

Any shareholder who so requests may obtain a printed copy of any of these documents from us. Changes in or waivers of our Code of Ethics for our Chief Executive Officer and Senior Financial Officers and waivers of our Ethics and Compliance Code for directors or executive officers will be posted on our Internet website within five business days of such change or waiver and maintained for at least 12 months or reported on Item 5.05 of Form 8-K. Our website address is
www.centerpointenergy.com.
Except to the extent explicitly stated herein, documents and information on our website are not incorporated by reference herein.

Electric Transmission & Distribution

In 1999, the Texas legislature adopted the Texas Electric Choice Plan (Texas electric restructuring law) that led to the restructuring of certain integrated electric utilities operating within Texas. Pursuant to that legislation, integrated electric utilities operating within the Electric Reliability Council of Texas, Inc. (ERCOT) were required to unbundle their integrated operations into separate retail sales, power generation and transmission and distribution companies. The legislation also required that the prices for wholesale generation and retail electric sales be unregulated, but

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services by companies providing transmission and distribution service, such as CenterPoint Houston, would remain regulated by the Public Utility Commission of Texas (Texas Utility Commission). The legislation provided for a transition period to move to the new market structure and provided a true-up mechanism for the formerly integrated electric utilities to recover stranded and certain other costs resulting from the transition to competition. Those costs were recoverable after approval by the Texas Utility Commission either through the issuance of securitization bonds or through the implementation of a competition transition charge (CTC) as a rider to the utility’s tariff.

CenterPoint Houston is a transmission and distribution electric utility that operates wholly within the state of Texas. Neither CenterPoint Houston nor any other subsidiary of CenterPoint Energy makes retail or wholesale sales of electric energy, or owns or operates any electric generating facilities.

Electric Transmission

On behalf of retail electric providers (REPs), CenterPoint Houston delivers electricity from power plants to substations, from one substation to another and to retail electric customers taking power at or above 69 kilovolts (kV) in locations throughout CenterPoint Houston’s certificated service territory. CenterPoint Houston constructs and maintains transmission facilities and provides transmission services under tariffs approved by the Texas Utility Commission.

Electric Distribution

In ERCOT, end users purchase their electricity directly from certificated REPs. CenterPoint Houston delivers electricity for REPs in its certificated service area by carrying lower-voltage power from the substation to the retail electric customer. CenterPoint Houston’s distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity to end users through distribution feeders. CenterPoint Houston’s operations include construction and maintenance of distribution facilities, metering services, outage response services and call center operations. CenterPoint Houston provides distribution services under tariffs approved by the Texas Utility Commission. Texas Utility Commission rules and market protocols govern the commercial operations of distribution companies and other market participants. Rates for these existing services are established pursuant to rate proceedings conducted before municipalities that have original jurisdiction and the Texas Utility Commission.

ERCOT Market Framework

CenterPoint Houston is a member of ERCOT. ERCOT serves as the regional reliability coordinating council for member electric power systems in Texas. ERCOT membership is open to consumer groups, investor and municipally-owned electric utilities, rural electric cooperatives, independent generators, power marketers, river authorities and REPs. The ERCOT market includes most of the State of Texas, other than a portion of the panhandle, portions of the eastern part of the state bordering Arkansas and Louisiana and the area in and around El Paso. The ERCOT market represents approximately 85% of the demand for power in Texas and is one of the nation’s largest power markets. The ERCOT market included available generating capacity of approximately 76,000 megawatts (MW) at December 31, 2010. There are only limited direct current interconnections between the ERCOT market and other power markets in the United States and Mexico.

The ERCOT market operates under the reliability standards set by the North American Electric Reliability Corporation (NERC) and approved by the Federal Energy Regulatory Commission (FERC). These reliability standards are administered by the Texas Regional Entity (TRE), a functionally independent division of ERCOT. The Texas Utility Commission has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state’s main interconnected power transmission grid. The ERCOT independent system operator (ERCOT ISO) is responsible for operating the bulk electric power supply system in the ERCOT market. Its responsibilities include ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. Unlike certain other regional power markets, the ERCOT market is not a centrally dispatched power pool, and the ERCOT ISO does not procure energy on behalf of its members other than to maintain the reliable operations of the transmission system. Members who sell and purchase power are responsible for contracting sales and purchases of power bilaterally. The ERCOT ISO also serves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.

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CenterPoint Houston’s electric transmission business, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO. The transmission business has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated area. CenterPoint Houston participates with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to increase bulk power transfer capability and to remove existing constraints on the ERCOT transmission grid.

Recovery of True-Up Balance

The Texas electric restructuring law substantially revised the regulatory structure governing electric utilities in order to allow retail competition for electric customers beginning in January 2002. The Texas electric restructuring law required the Texas Utility Commission to conduct a “true-up” proceeding to determine CenterPoint Houston’s stranded costs and certain other costs resulting from the transition to a competitive retail electric market and to provide for its recovery of those costs.

In March 2004, CenterPoint Houston filed its true-up application with the Texas Utility Commission, requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas electric restructuring law. In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and provided for adjustment of the amount to be recovered to include interest on the balance until recovery, along with the principal portion of additional excess mitigation credits (EMCs) returned to customers after August 31, 2004 and certain other adjustments.

CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, that court issued its judgment on the various appeals. In its judgment, the district court:

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reversed the Texas Utility Commission’s ruling that had denied CenterPoint Houston recovery of a portion of the capacity auction true-up amounts;

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reversed the Texas Utility Commission’s ruling that precluded CenterPoint Houston from recovering the interest component of the EMCs paid to REPs; and

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affirmed the True-Up Order in all other respects.

The district court’s decision would have had the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston’s initial request.

CenterPoint Houston and other parties appealed the district court’s judgment to the Texas Third Court of Appeals, which issued its decision in December 2007. In its decision, the court of appeals:

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reversed the district court’s judgment to the extent it restored the capacity auction true-up amounts;

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reversed the district court’s judgment to the extent it upheld the Texas Utility Commission’s decision to allow CenterPoint Houston to recover EMCs paid to its former affiliate Reliant Energy, Inc. (Reliant Energy, Inc., formerly known as Reliant Resources, Inc., changed its name in 2009 to “RRI Energy, Inc.” in connection with the sale of its Texas retail electric business, and again in December 2010 to “GenOn Energy, Inc.” in connection with the merger of one of its wholly owned subsidiaries with Mirant Corporation. For convenience, we refer to this company as “RRI” in the context of discussing transactions relating to our formation, our pending true-up appeal and other historical matters, and as “GenOn” in the present and future context, unless stated otherwise.);

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ordered that the tax normalization issue described below be remanded to the Texas Utility Commission as requested by the Texas Utility Commission; and

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affirmed the district court’s judgment in all other respects.

In April 2008, the court of appeals denied all motions for rehearing and reissued substantially the same opinion as it had rendered in December 2007.

In June 2008, CenterPoint Houston petitioned the Texas Supreme Court for review of the court of appeals decision. In its petition, CenterPoint Houston seeks reversal of the parts of the court of appeals decision that (i) denied recovery of EMCs paid to RRI, (ii) denied recovery of the capacity auction true-up amounts allowed by the district court, (iii) affirmed the Texas Utility Commission’s rulings that denied recovery of approximately $378 million related to depreciation and (iv) affirmed the Texas Utility Commission’s refusal to permit CenterPoint Houston to utilize the partial stock valuation methodology for determining the market value of its former generation assets. Two other petitions for review were filed with the Texas Supreme Court by other parties to the appeal. In those petitions parties contend that (i) the Texas Utility Commission was without authority to fashion the methodology it used for valuing the former generation assets after it had determined that CenterPoint Houston could not use the partial stock valuation method, (ii) in fashioning the method it used for valuing the former generating assets, the Texas Utility Commission deprived parties of their due process rights and an opportunity to be heard, (iii) the net book value of the generating assets should have been adjusted downward due to the impact of a purchase option that had been granted to RRI, (iv) CenterPoint Houston should not have been permitted to recover construction work in progress balances without proving those amounts in the manner required by law and (v) the Texas Utility Commission was without authority to award interest on the capacity auction true-up award.

In June 2009, the Texas Supreme Court granted the petitions for review of the court of appeals decision. Oral argument before the court was held in October 2009. Although we and CenterPoint Houston believe that CenterPoint Houston’s true-up request is consistent with applicable statutes and regulations and, accordingly, that it is reasonably possible that it will be successful in its appeal to the Texas Supreme Court, we can provide no assurance as to the ultimate court rulings on the issues to be considered in the appeal or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below.

To reflect the impact of the True-Up Order, in 2004 and 2005, we recorded a net after-tax extraordinary loss of $947 million. No amounts related to the district court’s judgment or the decision of the court of appeals have been recorded in our consolidated financial statements. However, if the court of appeals decision is not reversed or modified as a result of further review by the Texas Supreme Court, we anticipate that we would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue described below, but could range from $190 million to $440 million (pre-tax) plus interest subsequent to December 31, 2010.

In the True-Up Order, the Texas Utility Commission reduced CenterPoint Houston’s stranded cost recovery by approximately $146 million, which was included in the extraordinary loss discussed above, to reflect the present value of certain deferred tax benefits associated with its former electric generation assets. We believe that the Texas Utility Commission based its order on proposed regulations issued by the Internal Revenue Service (IRS) in March 2003 that would have allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes (EDFIT) back to customers. However, the IRS subsequently withdrew those proposed normalization regulations and, in March 2008, adopted final regulations that would not permit utilities like CenterPoint Houston to pass the tax benefits back to customers without creating normalization violations. In addition, we received a Private Letter Ruling (PLR) from the IRS in August 2007, prior to adoption of the final regulations, that confirmed that the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations with respect to the ADITC and EDFIT.

If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require us to pay an amount equal to CenterPoint Houston’s unamortized ADITC balance as of the date that the normalization violation is deemed to have occurred. In addition, the IRS could deny CenterPoint Houston the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. Such treatment, if required by the IRS, could have a material adverse impact on our results of operations, financial condition and cash

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flows in addition to any potential loss resulting from final resolution of the True-Up Order. Following the adoption by the IRS of the final regulations described above, the Texas Utility Commission requested, and the court of appeals ordered, that this issue be remanded to that commission for further consideration. No party has challenged that order by the court of appeals although the Texas Supreme Court has the authority to consider all aspects of the rulings above, not just those challenged specifically by the appellants. We and CenterPoint Houston will continue to pursue a favorable resolution of this issue through the appellate and administrative process. Although the Texas Utility Commission has requested that this issue be remanded to it by the courts and has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

The Texas electric restructuring law allowed the amounts awarded to CenterPoint Houston in the Texas Utility Commission’s True-Up Order to be recovered either through securitization or through implementation of a CTC or both. Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed by a Travis County district court, in December 2005, a new special purpose subsidiary of CenterPoint Houston issued $1.85 billion in transition bonds with interest rates ranging from 4.84% to 5.30% and final maturity dates ranging from February 2011 to August 2020. Through issuance of the transition bonds, CenterPoint Houston recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus interest through the date on which the bonds were issued.

In July 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC designed to collect the remaining $596 million from the True-Up Order over 14 years plus interest at an annual rate of 11.075% (CTC Order). The CTC Order authorized CenterPoint Houston to impose a charge on REPs to recover the portion of the true-up balance not recovered through a financing order. The CTC Order also allowed CenterPoint Houston to collect approximately $24 million of rate case expenses over three years without a return through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $620 million. The return on the CTC portion of the true-up balance was included in CenterPoint Houston’s tariff-based revenues beginning September 13, 2005. Effective August 1, 2006, the interest rate on the unrecovered balance of the CTC was reduced from 11.075% to 8.06% pursuant to a revised rule adopted by the Texas Utility Commission in June 2006. Recovery of rate case expenses under Rider RCE was completed in September 2008.

Certain parties appealed the CTC Order to a district court in Travis County. In May 2006, the district court issued a judgment reversing the CTC Order in three respects. First, the court ruled that the Texas Utility Commission had improperly relied on provisions of its rule dealing with the interest rate applicable to CTC amounts. The district court reached that conclusion based on its belief that the Texas Supreme Court had previously invalidated that entire section of the rule. The 11.075% interest rate in question was applicable from the implementation of the CTC Order on September 13, 2005 until August 1, 2006, the effective date of the implementation of a new CTC in compliance with the revised rule discussed above. Second, the district court reversed the Texas Utility Commission’s ruling that allows CenterPoint Houston to recover through Rider RCE the costs (approximately $5 million) for a panel appointed by the Texas Utility Commission in connection with the valuation of electric generation assets. Finally, the district court accepted the contention of one party that the CTC should not be allocated to retail customers that have switched to new on-site generation. The Texas Utility Commission and CenterPoint Houston appealed the district court’s judgment to the Texas Third Court of Appeals, and in July 2008, the court of appeals reversed the district court’s judgment in all respects and affirmed the Texas Utility Commission’s order. Two parties appealed the court of appeals decision to the Texas Supreme Court and on October 22, 2010, the Texas Supreme Court issued an opinion affirming the judgment of the court of appeals. The Texas Supreme Court’s decision did not have an impact on our or CenterPoint Houston’s financial position, results of operations or cash flows.

During the 2007 legislative session, the Texas legislature amended statutes prescribing the types of true-up balances that can be securitized by utilities and authorized the issuance of transition bonds to recover the balance of the CTC. In June 2007, CenterPoint Houston filed a request with the Texas Utility Commission for a financing order that would allow the securitization of the remaining balance of the CTC, adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the final fuel reconciliation settlement. CenterPoint Houston reached substantial agreement with other parties to this proceeding, and a financing order was approved by the Texas Utility Commission in September 2007. In February 2008, pursuant to the financing order, a new special purpose subsidiary of CenterPoint Houston issued approximately $488 million of transition bonds in two tranches

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with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Contemporaneously with the issuance of those bonds, the CTC was terminated and a transition charge was implemented. During the year ended December 31, 2008, CenterPoint Houston recognized approximately $5 million in operating income from the CTC.

As of December 31, 2010, we have not recognized an allowed equity return of $178 million on CenterPoint Houston’s true-up balance because such return will be recognized as it is recovered in rates. During the years ended December 31, 2008, 2009 and 2010, CenterPoint Houston recognized approximately $13 million, $13 million and $15 million, respectively, of the allowed equity return.

Hurricane Ike

CenterPoint Houston’s electric delivery system suffered substantial damage as a result of Hurricane Ike, which struck the upper Texas coast in September 2008. CenterPoint Houston deferred the system restoration costs as management believed it was probable that such costs would be recovered through the regulatory process. As a result, system restoration costs did not affect our or CenterPoint Houston’s reported operating income for 2008 or 2009.

CenterPoint Houston filed with the Texas Utility Commission an application for review and approval for recovery of approximately $678 million, including approximately $608 million in system restoration costs identified as of the end of February 2009, plus $2 million in regulatory expenses, $13 million in certain debt issuance costs and $55 million in incurred and projected carrying costs calculated through August 2009. In July 2009, CenterPoint Houston reached a settlement agreement with the parties to the proceeding. Under that settlement agreement, CenterPoint Houston was entitled to recover a total of $663 million in costs relating to Hurricane Ike, along with carrying
costs from September 1, 2009 until system restoration bonds were issued. The Texas Utility Commission issued an order in August 2009 approving the settlement agreement and authorizing recovery of $663 million, of which $643 million was attributable to distribution service and eligible for securitization and the remaining $20 million was attributable to transmission service and eligible for recovery through the existing mechanisms established to recover transmission costs.

In August 2009, the Texas Utility Commission issued a financing order allowing CenterPoint Houston to securitize $643 million in distribution service costs plus carrying charges from September 1, 2009 through the date the system restoration bonds were issued, as well as certain up-front qualified costs capped at approximately $6 million. In November 2009, CenterPoint Houston issued approximately $665 million of system restoration bonds through its CenterPoint Energy Restoration Bond Company, LLC subsidiary with interest rates of 1.833% to 4.243% and final maturity dates ranging from February 2016 to August 2023. The bonds will be repaid over time through a charge imposed on customers.

In accordance with the financing order, CenterPoint Houston also placed a separate customer credit in effect when the storm restoration bonds were issued. That credit (ADFIT Credit) is applied to customers’ bills while the bonds are outstanding to reflect the benefit of accumulated deferred federal income taxes (ADFIT) associated with the storm restoration costs (including a carrying charge of 11.075%). The beginning balance of the ADFIT related to storm restoration costs was approximately $207 million and will decline over the life of the system restoration bonds as taxes are paid on the system restoration tariffs. The ADFIT Credit reduced operating income in 2010 by approximately $23 million.

Customers

CenterPoint Houston serves nearly all of the Houston/Galveston metropolitan area. CenterPoint Houston’s customers consist of 99 REPs, which sell electricity to over two million metered customers in CenterPoint Houston’s certificated service area, and municipalities, electric cooperatives and other distribution companies located outside CenterPoint Houston’s certificated service area. Each REP is licensed by, and must meet minimum creditworthiness criteria established by, the Texas Utility Commission.

and 12% of CenterPoint Houston’s transmission and distribution revenues in 2008, 2009 and 2010, respectively. CenterPoint Houston’s billed receivables balance from REPs as of December 31, 2010 was $138 million. Approximately 33% and 13% of this amount was owed by subsidiaries of NRG Retail and TXU Energy Retail, respectively. CenterPoint Houston does not have long-term contracts with any of its customers. It operates using a continuous billing cycle, with meter readings being conducted and invoices being distributed to REPs each business day.

In December 2008, CenterPoint Houston received approval from the Texas Utility Commission to deploy an advanced metering system (AMS) across its service territory over the next five years. CenterPoint Houston began installing advanced meters in March 2009. This innovative technology should encourage greater energy conservation by giving Houston-area electric consumers the ability to better monitor and manage their electric use and its cost in near real time. CenterPoint Houston is currently recovering the cost for the AMS through a monthly surcharge to all REPs over 12 years. The surcharge for each residential consumer for the first 24 months, which began in February 2009, was $3.24 per month. Beginning in February 2011, the surcharge was reduced to $3.05 per month. These amounts are subject to upward or downward adjustment in future proceedings to reflect actual costs incurred and to address required changes in scope.

CenterPoint Houston is also pursuing deployment of an electric distribution grid automation strategy that involves the implementation of an “Intelligent Grid” (IG) which would make use of CenterPoint Houston’s facilities to provide on-demand data and information about the status of facilities on its system. Although this technology is still in the developmental stage, CenterPoint Houston believes it has the potential to provide a significant improvement in grid planning, operations, maintenance and customer service for the CenterPoint Houston distribution system. These improvements are expected to contribute to fewer and shorter outages, better customer service, improved operations costs, improved security and more effective use of our workforce. We expect to include the costs of the deployment in future rate proceedings before the Texas Utility Commission.

In October 2009, the U.S. Department of Energy (DOE) notified CenterPoint Houston that it had been selected for a $200 million grant for its AMS and IG projects. In March 2010, CenterPoint Houston and the DOE completed negotiations and finalized the agreement. Under the terms of the agreement, the DOE has agreed to reimburse CenterPoint Houston for 50% of its eligible costs until the total amount of the grant has been paid. Through December 31, 2010, CenterPoint Houston has requested $100 million of grant funding from the DOE, of which $90 million had been received. CenterPoint Houston estimates that capital expenditures of approximately $645 million for the installation of the advanced meters and corresponding communication and data management systems will be incurred over the deployment period. CenterPoint Houston is using $150 million of the grant funding to accelerate completion of its current deployment of advanced meters to 2012, instead of 2014 as originally scheduled. CenterPoint Houston will use the other $50 million from the grant to begin deployment of an IG in a portion of its service territory over the next three years. It is expected that the portion of the IG project subject to funding by the DOE will cost approximately $115 million.

In March 2010, the IRS announced through the issuance of Revenue Procedure 2010-20 that it was providing a safe harbor to corporations that receive a Smart Grid Investment Grant. The IRS stated that it would not challenge a corporation’s treatment of the grant as a non-taxable non-shareholder contribution to capital as long as the corporation properly reduced the tax basis of specified property acquired.

Competition

There are no other electric transmission and distribution utilities in CenterPoint Houston’s service area. In order for another provider of transmission and distribution services to provide such services in CenterPoint Houston’s territory, it would be required to obtain a certificate of convenience and necessity from the Texas Utility Commission and, depending on the location of the facilities, may also be required to obtain franchises from one or more municipalities. We know of no other party intending to enter this business in CenterPoint Houston’s service area at this time.

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Seasonality

A significant portion of CenterPoint Houston’s revenues is derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of such REP. Thus, CenterPoint Houston’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues being higher during the warmer months.

Properties

All of CenterPoint Houston’s properties are located in Texas. Its properties consist primarily of high voltage electric transmission lines and poles, distribution lines, substations, service wires and meters. Most of CenterPoint Houston’s transmission and distribution lines have been constructed over lands of others pursuant to easements or along public highways and streets as permitted by law.

All real and tangible properties of CenterPoint Houston, subject to certain exclusions, are currently subject to:

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the lien of a Mortgage and Deed of Trust (the Mortgage) dated November 1, 1944, as supplemented; and

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the lien of a General Mortgage (the General Mortgage) dated October 10, 2002, as supplemented, which is junior to the lien of the Mortgage.

As of December 31, 2010, CenterPoint Houston had approximately $2.5 billion aggregate principal amount of general mortgage bonds outstanding under the General Mortgage, including (a) $290 million held in trust to secure pollution control bonds that are not reflected on our consolidated financial statements because we are both the obligor on the bonds and the owner of the bonds, (b) an additional approximately $237 million held in trust to secure pollution control bonds for which we are obligated and (c) approximately $229 million held in trust to secure pollution control bonds for which CenterPoint Houston is obligated. Additionally, CenterPoint Houston had approximately $253 million aggregate principal amount of first mortgage bonds outstanding under the Mortgage, including approximately $151 million held in trust to secure certain pollution control bonds for which we are obligated. CenterPoint Houston may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $2.3 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2010. However, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

Electric Lines — Overhead.
As of December 31, 2010, CenterPoint Houston owned 27,842 pole miles of overhead distribution lines and 3,728 circuit miles of overhead transmission lines, including 422 circuit miles operated at 69,000 volts, 2,090 circuit miles operated at 138,000 volts and 1,216 circuit miles operated at 345,000 volts.

Electric Lines — Underground.
As of December 31, 2010, CenterPoint Houston owned 20,390 circuit miles of underground distribution lines and 26 circuit miles of underground transmission lines, including 2 circuit miles operated at 69,000 volts and 24 circuit miles operated at 138,000 volts.

Substations.
As of December 31, 2010, CenterPoint Houston owned 233 major substation sites having a total installed rated transformer capacity of 52,938 megavolt amperes.

Service Centers.
CenterPoint Houston operates 14 regional service centers located on a total of 291 acres of land. These service centers consist of office buildings, warehouses and repair facilities that are used in the business of transmitting and distributing electricity.

Franchises

CenterPoint Houston holds non-exclusive franchises from the incorporated municipalities in its service territory. In exchange for the payment of fees, these franchises give CenterPoint Houston the right to use the streets and public rights-of way of these municipalities to construct, operate and maintain its transmission and distribution

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system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 30 to 50 years.

Natural Gas Distribution

CERC Corp.’s natural gas distribution business (Gas Operations) engages in regulated intrastate natural gas sales to, and natural gas transportation for, approximately 3.3 million residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. The largest metropolitan areas served in each state by Gas Operations are Houston, Texas; Minneapolis, Minnesota; Little Rock, Arkansas; Shreveport, Louisiana; Biloxi, Mississippi; and Lawton, Oklahoma. In 2010, approximately 42% of Gas Operations’ total throughput was to residential customers and approximately 58% was to commercial and industrial customers.

The table below reflects the number of natural gas distribution customers by state as of December 31, 2010:

Residential

Commercial/

Industrial

Total Customers

Arkansas

390,668

48,033

438,701

Louisiana

232,135

17,347

249,482

Minnesota

738,868

67,489

806,357

Mississippi

109,608

12,683

122,291

Oklahoma

93,388

10,620

104,008

Texas

1,451,666

90,719

1,542,385

Total Gas Operations

3,016,333

246,891

3,263,224

Gas Operations also provides unregulated services consisting of heating, ventilating and air conditioning (HVAC) equipment and appliance repair, and sales of HVAC, hearth and water heating equipment in Minnesota.

The demand for intrastate natural gas sales to residential customers and natural gas sales and transportation for commercial and industrial customers is seasonal. In 2010, approximately 71% of the total throughput of Gas Operations’ business occurred in the first and fourth quarters. These patterns reflect the higher demand for natural gas for heating purposes during those periods.

Supply and Transportation.
In 2010, Gas Operations purchased virtually all of its natural gas supply pursuant to contracts with remaining terms varying from a few months to four years. Major suppliers in 2010 included BP Canada Energy Marketing Corp. (25.6% of supply volumes), ConocoPhillips Company (8.3%), Tenaska Marketing Ventures (6.8%), Kinder Morgan (6.3%), Oneok Energy Marketing Company (4.7%), and Cargill, Inc. (4.6%). Numerous other suppliers provided the remaining 43.7% of Gas Operations’ natural gas supply requirements. Gas Operations transports its natural gas supplies through various intrastate and interstate pipelines, including those owned by our other subsidiaries, under contracts with remaining terms, including extensions, varying from one to twelve years. Gas Operations anticipates that these gas supply and transportation contracts will be renewed or replaced prior to their expiration.

Gas Operations actively engages in commodity price stabilization pursuant to annual gas supply plans presented to and/or filed with each of its state regulatory authorities. These price stabilization activities include use of storage gas, contractually establishing fixed prices with our physical gas suppliers and utilizing financial derivative instruments to achieve a variety of pricing structures (e.g., fixed price, costless collars and caps). Its gas supply plans generally call for 25-50% of winter supplies to be hedged in some fashion.

Generally, the regulations of the states in which Gas Operations operates allow it to pass through changes in the cost of natural gas, including gains and losses on financial derivatives associated with the index-priced physical supply, to its customers under purchased gas adjustment provisions in its tariffs. Depending upon the jurisdiction, the purchased gas adjustment factors are updated periodically, ranging from monthly to semi-annually, using estimated gas costs. The changes in the cost of gas billed to customers are subject to review by the applicable regulatory bodies.

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Gas Operations uses various third-party storage services or owned natural gas storage facilities to meet peak-day requirements and to manage the daily changes in demand due to changes in weather and may also supplement contracted supplies and storage from time to time with stored liquefied natural gas and propane-air plant production.

Gas Operations owns and operates an underground natural gas storage facility with a capacity of 7.0 billion cubic feet (Bcf). It has a working capacity of 2.0 Bcf available for use during a normal heating season and a maximum daily withdrawal rate of 50 million cubic feet (MMcf). It also owns nine propane-air plants with a total production rate of 200,000 Dekatherms (DTH) per day and on-site storage facilities for 12 million gallons of propane (1.0 Bcf natural gas equivalent). It owns a liquefied natural gas plant facility with a 12 million-gallon liquefied natural gas storage tank (1.0 Bcf natural gas equivalent) and a production rate of 72,000 DTH per day.

On an ongoing basis, Gas Operations enters into contracts to provide sufficient supplies and pipeline capacity to meet its customer requirements. However, it is possible for limited service disruptions to occur from time to time due to weather conditions, transportation constraints and other events. As a result of these factors, supplies of natural gas may become unavailable from time to time, or prices may increase rapidly in response to temporary supply constraints or other factors.

Gas Operations has entered into various asset management agreements associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas. Generally, these asset management agreements are contracts between Gas Operations and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, Gas Operations agreed to release transportation and storage capacity to other parties to manage gas storage, supply and delivery arrangements for Gas Operations and to use the released capacity for other purposes when it is not needed for Gas Operations. Gas Operations is compensated by the asset manager through payments made over the life of the agreements based in part on the results of the asset optimization. Gas Operations has received approval from the state regulatory commissions in Arkansas, Louisiana, Mississippi and Oklahoma to retain a share of the asset management agreement proceeds, although the percentage of payments to be retained by Gas Operations varies based on the jurisdiction, with the majority of the payments to benefit customers. The agreements have varying terms, the longest of which expires in 2016.

Assets

As of December 31, 2010, Gas Operations owned approximately 71,000 linear miles of natural gas distribution mains, varying in size from one-half inch to 24 inches in diameter. Generally, in each of the cities, towns and rural areas served by Gas Operations, it owns the underground gas mains and service lines, metering and regulating equipment located on customers’ premises and the district regulating equipment necessary for pressure maintenance. With a few exceptions, the measuring stations at which Gas Operations receives gas are owned, operated and maintained by others, and its distribution facilities begin at the outlet of the measuring equipment. These facilities, including odorizing equipment, are usually located on land owned by suppliers.

Competition

Gas Operations competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other gas distributors and marketers also compete directly for gas sales to end-users. In addition, as a result of federal regulations affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass Gas Operations’ facilities and market and sell and/or transport natural gas directly to commercial and industrial customers.

In 2010, CES marketed approximately 548 Bcf of natural gas, related energy services and transportation to approximately 12,200 customers (including approximately 7 Bcf to affiliates). CES customers vary in size from

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small commercial customers to large utility companies in the central and eastern regions of the United States. The business has three operational divisions: wholesale, retail and intrastate pipelines, which are further described below.

Wholesale Division.
CES offers a portfolio of physical delivery services and financial products designed to meet wholesale customers’ supply and price risk management needs. These customers are served directly through interconnects with various interstate and intrastate pipeline companies, and include gas utilities, large industrial customers and electric generation customers. This division includes the supply function for the procurement of natural gas and the management and optimization of transportation and storage assets for CES.

Intrastate Pipeline Division.
CEIP provides transportation services to shippers and end-users and contracts out approximately 2.3 Bcf of storage at its Pierce Junction facility in Texas.

CES currently transports natural gas on over 40 interstate and intrastate pipelines within states located throughout the central and eastern United States. CES maintains a portfolio of natural gas supply contracts and firm transportation and storage agreements to meet the natural gas requirements of its customers. CES aggregates supply from various producing regions and offers contracts to buy natural gas with terms ranging from one month to over five years. In addition, CES actively participates in the spot natural gas markets in an effort to balance daily and monthly purchases and sales obligations. Natural gas supply and transportation capabilities are leveraged through contracts for ancillary services including physical storage and other balancing arrangements.

As described above, CES offers its customers a variety of load following services. In providing these services, CES uses its customers’ purchase commitments to forecast and arrange its own supply purchases, storage and transportation services to serve customers’ natural gas requirements. As a result of the variance between this forecast activity and the actual monthly activity, CES will either have too much supply or too little supply relative to its customers’ purchase commitments. These supply imbalances arise each month as customers’ natural gas requirements are scheduled and corresponding natural gas supplies are nominated by CES for delivery to those customers. CES’ processes and risk control environment are designed to measure and value imbalances on a real-time basis to ensure that CES’ exposure to commodity price risk is kept to a minimum. The value assigned to these imbalances is calculated daily and is known as the aggregate Value at Risk (VaR).

Our risk control policy, which is overseen by our Risk Oversight Committee, defines authorized and prohibited trading instruments and trading limits. CES is a physical marketer of natural gas and uses a variety of tools, including pipeline and storage capacity, financial instruments and physical commodity purchase contracts to support its sales. The CES business optimizes its use of these various tools to minimize its supply costs and does not engage in proprietary or speculative commodity trading. The VaR limits within which CES operates, a $4 million maximum, are consistent with CES’ operational objective of matching its aggregate sales obligations (including the swing associated with load following services) with its supply portfolio in a manner that minimizes its total cost of supply. In 2010, CES’ VaR averaged $0.7 million with a high of $1.7 million.

Assets

CEIP owns and operates approximately 233 miles of intrastate pipeline in Louisiana and Texas and holds storage facilities of approximately 2.3 Bcf in Texas under long-term leases. In addition, CES leases transportation capacity of approximately 0.9 Bcf per day on various interstate and intrastate pipelines and approximately 15.4 Bcf of storage to service its customer base.

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Competition

CES competes with regional and national wholesale and retail gas marketers including the marketing divisions of natural gas producers and utilities. In addition, CES competes with intrastate pipelines for customers and services in its market areas.

The rates charged by CEGT and MRT for interstate transportation and storage services are regulated by the FERC. CERC's interstate pipelines business operations may be affected by changes in the demand for natural gas, the available supply and relative price of natural gas in the Mid-continent and Gulf Coast natural gas supply regions and general economic conditions.

In 2010, approximately 16% of CEGT and MRT’s total operating revenue was attributable to services provided to Gas Operations, an affiliate, and approximately 7% was attributable to services provided to Laclede Gas Company (Laclede), an unaffiliated distribution company, that provides natural gas utility service to the greater St. Louis metropolitan area in Illinois and Missouri. Services to Gas Operations and Laclede are provided under several long-term firm storage and transportation agreements. The primary term of MRT’s firm transportation and storage contracts with Laclede will expire in 2013. In May 2010, Gas Operations and CEGT reached an agreement to renew the contracts for terms extending through March 31, 2021. All applicable regulatory approvals have been received.

Carthage to Perryville.
In February 2010, CEGT completed the expansion of the capacity of its Carthage to Perryville pipeline to approximately 1.9 Bcf per day. The 274 MMcf per day expansion includes new compressor units at two of CEGT’s existing stations.

Southeast Supply Header, LLC.
CenterPoint Southeastern Pipelines Holding, LLC, a wholly-owned subsidiary of CERC, owns a 50% interest in Southeast Supply Header, LLC (SESH). SESH owns a 1.0 Bcf per day, 274-mile interstate pipeline that runs from the Perryville Hub in Louisiana to Coden, Alabama. The pipeline was placed into service in September 2008. The rates charged by SESH for interstate transportation services are regulated by the FERC. A wholly-owned, indirect subsidiary of Spectra Energy Corp. owns the remaining 50% interest in SESH.

Assets

CERC's interstate pipelines business currently owns and operates approximately 8,000 miles of natural gas transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. CERC's interstate pipeline business also owns and operates six natural gas storage fields with a combined daily deliverability of approximately 1.3 Bcf and a combined working gas capacity of approximately 59 Bcf. CERC's interstate pipeline business also owns a 10% interest in the Bistineau storage facility located in Bienville Parish, Louisiana, with the remaining interest owned and operated by Gulf South Pipeline Company, LP. CERC's interstate pipeline business' storage capacity in the Bistineau facility is 8 Bcf of working gas with 100 MMcf per day of deliverability. Most storage operations are in north Louisiana and Oklahoma.

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Competition

CERC's interstate pipelines business competes with other interstate and intrastate pipelines in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service, and flexibility and reliability of service. CERC's interstate pipelines business competes indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price, but environmental considerations have grown in importance when consumers consider alternative forms of energy. Changes in the availability of energy and pipeline capacity, the level of business activity, conservation and governmental regulations, the capability to convert to alternative fuels, and other factors, including weather, affect the demand for natural gas in areas we serve and the level of competition for transportation and storage services.

Field Services

CERC’s field services business operates gas gathering, treating and processing facilities and also provides operating and technical services and remote data monitoring and communication services.

CERC’s field services operations are conducted by a wholly owned subsidiary, CenterPoint Energy Field Services, LLC. (CEFS). CEFS provides natural gas gathering and processing services for certain natural gas fields in the Mid-continent region of the United States that interconnect with CEGT’s and MRT’s pipelines, as well as other interstate and intrastate pipelines. CEFS gathers approximately 2.0 Bcf per day of natural gas and, either directly or through its 50% interest in a joint venture, processes in excess of 260 MMcf per day of natural gas along its gathering system. CEFS, through its ServiceStar operating division, provides remote data monitoring and communications services to affiliates and third parties.

CERC's field services business operations may be affected by changes in the demand for natural gas and natural gas liquids (NGLs), the available supply and relative price of natural gas and NGLs in the Mid-continent and Gulf Coast natural gas supply regions and general economic conditions.

Magnolia Gathering System.
In September 2009, CEFS entered into long-term agreements with an indirect wholly-owned subsidiary of Encana Corporation (Encana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Louisiana. Pursuant to these agreements, CEFS acquired jointly-owned gathering facilities (the Magnolia Gathering System) from Encana and Shell in northwest Louisiana. Each of the agreements includes acreage dedication and volume commitments for which CEFS has exclusive rights to gather Shell’s and Encana’s natural gas production.

During the year ended December 31, 2010, CEFS substantially completed the construction and initial expansion of the Magnolia Gathering System in order to permit the system to gather and treat up to 700 MMcf per day of natural gas, with only well connects remaining. As of December 31, 2010, CEFS had spent approximately $310 million on the original project scope, including the purchase of the original facilities and is in the second year of the 10-year 700 MMcf per day volume commitment made by Shell and Encana.

Pursuant to an expansion election made by Encana and Shell in March 2010, CEFS expanded the Magnolia Gathering System to increase its gathering and treating capacity by an additional 200 MMcf per day, increasing the aggregate capacity of the system to 900 MMcf per day. As of December 31, 2010, CEFS had spent approximately $47 million on the expansion. The expansion was completed and placed into service in February, 2011 at a total cost of approximately $52 million. The 200 MMcf per day incremental volume commitment made by Shell and Encana began contemporaneously with the completion of the expansion.

Under the long-term agreements, Encana or Shell may elect to require CEFS to expand the capacity of the Magnolia Gathering System by up to an additional 800 MMcf per day, bringing the total system capacity to 1.7 Bcf per day. CEFS estimates that the cost to expand the capacity of the Magnolia Gathering System by an additional 800 MMcf per day would be as much as $240 million. Encana and Shell would provide incremental volume commitments in connection with an election to expand the system’s capacity.

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Olympia Gathering System.
In April 2010, CEFS entered into additional long-term agreements with Encana and Shell to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Texas and Louisiana. Pursuant to these agreements, CEFS acquired jointly-owned gathering facilities (the Olympia Gathering System) from Encana and Shell in northwest Louisiana.

Under the terms of the agreements, CEFS is expanding the Olympia Gathering System in order to permit the system to gather and treat up to 600 MMcf per day of natural gas. As of December 31, 2010, CEFS had spent approximately $340 million on the 600 MMcf per day project, including the purchase of the original facilities, and expects to incur up to an additional $85 million to complete this expansion. CEFS expects the full 600 MMcf per day of capacity to be in service in the first quarter of 2011. CEFS is in the first year of the 10-year 600 MMcf per day volume commitment made by Shell and Encana .

Under the long-term agreements, Encana and Shell may elect to require CEFS to expand the capacity of the Olympia Gathering System by up to an additional 520 MMcf per day, bringing the total system capacity to 1.1 Bcf per day. CEFS estimates that the cost to expand the capacity of the Olympia Gathering System by an additional 520 MMcf per day would be as much as $200 million. Encana and Shell would provide incremental volume commitments in connection with an election to expand the system’s capacity.

Waskom Gas Processing Company.
CenterPoint Energy Gas Processing Company, a wholly-owned, indirect subsidiary of CERC, owns a 50% general partnership interest in Waskom Gas Processing Company (Waskom). Waskom owns a natural gas processing plant and natural gas gathering assets located in East Texas. The plant is capable of processing approximately 285 MMcf per day of natural gas. The gathering assets are capable of gathering approximately 75 MMcf per day of natural gas.

Assets

CERC’s field services business owns and operates approximately 3,800 miles of gathering lines and processing plants that collect, treat and process natural gas primarily from three regions located in major producing fields in Arkansas, Louisiana, Oklahoma and Texas.

Competition

CERC's field services business competes with other companies in the natural gas gathering, treating and processing business. The principal elements of competition are rates, terms of service and reliability of services. CERC's field services business competes indirectly with alternative forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price, but environmental considerations have grown in importance when consumers consider other forms of energy. Changes in the availability of energy and pipeline capacity, the level of business activity, conservation and governmental regulations, the capability to convert to alternative fuels, and other factors, including weather, affect the demand for natural gas in areas we serve and the level of competition for gathering, treating, and processing services. In addition, competition among forms of energy is affected by commodity pricing levels and influences the level of drilling activity and demand for our gathering operations.

Other Operations

Our Other Operations business segment includes office buildings and other real estate used in our business operations and other corporate operations that support all of our business operations.

Financial Information About Segments

For financial information about our segments, see Note 16 to our consolidated financial statements, which note is incorporated herein by reference.

REGULATION

We are subject to regulation by various federal, state and local governmental agencies, including the regulations described below.

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Federal Energy Regulatory Commission

The FERC has jurisdiction under the Natural Gas Act and the Natural Gas Policy Act of 1978, as amended, to regulate the transportation of natural gas in interstate commerce and natural gas sales for resale in interstate commerce that are not first sales. The FERC regulates, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. The rates charged by interstate pipelines for interstate transportation and storage services are also regulated by the FERC. The Energy Policy Act of 2005 (Energy Act) expanded the FERC’s authority to prohibit market manipulation in connection with FERC-regulated transactions and gave the FERC additional authority to impose significant civil and criminal penalties for statutory violations and violations of the FERC’s rules or orders and also expanded criminal penalties for such violations. Our competitive natural gas sales and services subsidiary markets natural gas in interstate commerce pursuant to blanket authority granted by the FERC.

CERC's natural gas pipeline subsidiaries may periodically file applications with the FERC for changes in their generally available maximum rates and charges designed to allow them to recover their costs of providing service to customers (to the extent allowed by prevailing market conditions), including a reasonable rate of return. These rates are normally allowed to become effective after a suspension period and, in some cases, are subject to refund under applicable law until such time as the FERC issues an order on the allowable level of rates.

CenterPoint Houston is not a “public utility” under the Federal Power Act and, therefore, is not generally regulated by the FERC, although certain of its transactions are subject to limited FERC jurisdiction. The Energy Act conferred new jurisdiction and responsibilities on the FERC with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by CenterPoint Houston and other utilities within ERCOT. Under this authority, the FERC has designated the NERC as the Electric Reliability Organization (ERO) to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system (Electric Entities). The ERO and the FERC have authority to (a) impose fines and other sanctions on Electric Entities that fail to comply with approved standards and (b) audit compliance with approved standards. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the TRE. CenterPoint Houston does not anticipate that the reliability standards proposed by the NERC and approved by the FERC will have a material adverse impact on its operations. To the extent that CenterPoint Houston is required to make additional expenditures to comply with these standards, it is anticipated that CenterPoint Houston will seek to recover those costs through the transmission charges that are imposed on all distribution service providers within ERCOT for electric transmission provided.

As a public utility holding company, under the Public Utility Holding Company Act of 2005, we and our subsidiaries are subject to reporting and accounting requirements and are required to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances.

State and Local Regulation

Electric Transmission & Distribution

CenterPoint Houston conducts its operations pursuant to a certificate of convenience and necessity issued by the Texas Utility Commission that covers its present service area and facilities. The Texas Utility Commission and those municipalities that have retained original jurisdiction have the authority to set the rates and terms of service provided by CenterPoint Houston under cost of service rate regulation. CenterPoint Houston holds non-exclusive franchises from the incorporated municipalities in its service territory. In exchange for payment of fees, these franchises give CenterPoint Houston the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 30 to 50 years.

CenterPoint Houston’s distribution rates charged to REPs for residential customers are primarily based on amounts of energy delivered, whereas distribution rates for a majority of commercial and industrial customers are primarily based on peak demand. All REPs in CenterPoint Houston’s service area pay the same rates and other charges for transmission and distribution services. This regulated delivery charge includes the transmission and

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distribution rate (which includes municipal franchise fees), a system benefit fund fee imposed by the Texas electric restructuring law, a nuclear decommissioning charge associated with decommissioning the South Texas nuclear generating facility, an energy efficiency cost recovery charge, a surcharge related to the implementation of AMS and charges associated with securitization of regulatory assets, stranded costs and restoration costs relating to Hurricane Ike. Transmission rates charged to other distribution companies are based on amounts of energy transmitted under “postage stamp” rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay CenterPoint Houston the same rates and other charges for transmission services.

2010 Rate Proceeding
.
As required under the final order in its 2006 rate proceeding, in June 2010 CenterPoint Houston filed an application to change rates with the Texas Utility Commission and the cities in its service area, including cost data and other information supporting an annual increase of $106 million for delivery charges to the REPs that sell electricity to end-use customers in CenterPoint Houston’s service territory that was offset by a reduction of other utility revenues, resulting in a $92 million requested annual revenue increase. The rate filing package also supported an annual increase of $18 million for wholesale transmission customers.

In the filing, CenterPoint Houston also requested reconciliation of its AMS costs incurred as of March 31, 2010, and revision of the estimated costs to complete the AMS project in order to reflect $150 million in funds from the $200 million DOE stimulus grant awarded to CenterPoint Houston and updated cost information. The reconciliation plan also requested that the duration of the residential AMS surcharge be shortened by six years from the original 12-year plan.

In its rate filing, CenterPoint Houston sought a return on equity of 11.25% and proposed that rates be based on a capital structure of 50% equity and 50% long-term debt.

Hearings concerning the rate filing concluded in October 2010, and a Proposal for Decision was issued by the presiding Administrative Law Judges. On February 3, 2011 the Texas Utility Commission voted on the various contested issues presented by the rate filing. The Texas Utility Commission has not yet issued a formal order implementing its decisions, and the order, once issued, will be subject to revision based on motions for rehearing by the parties to the proceeding and could be appealed to the Texas courts.

Based on the public deliberations and votes by the Commissioners, CenterPoint Houston anticipates that the order of the Texas Utility Commission will provide for a base rate increase for CenterPoint Houston of approximately $14.7 million per year for delivery charges to the REPs and a decrease to charges to wholesale transmission customers of $12.3 million per year. Further, the order is expected to provide a mechanism to track amounts for uncertain tax positions and provide for ultimate recovery of those costs.

The order is expected to be based on an authorized return on equity for CenterPoint Houston of 10%, a cost of debt of ­6.74­%, a capital structure comprised of 55% debt and 45% common equity, and an overall rate of return of 8.21%. The decision also will implement CenterPoint Houston’s request to reconcile costs incurred for the AMS project and to shorten the period for collecting the AMS surcharge from twelve to six years for residential customers in order to reflect the funds received from the DOE.

Based on CenterPoint Houston’s understanding of the Texas Utility Commission’s votes, CenterPoint Houston anticipates that annual operating income will be reduced by approximately $30 million from 2010 levels as a result of the Texas Utility Commission’s decision. CenterPoint Houston expects that revised rates based on the Texas Utility Commission’s decision will be implemented during the second quarter of 2011.

Other Rate Proceedings.
In May 2009, CenterPoint Houston filed an application at the Texas Utility Commission seeking approval of certain estimated 2010 energy efficiency program costs, an energy efficiency performance bonus for 2008 programs, and carrying costs totaling approximately $10 million. The application sought to begin recovery of these costs through a surcharge effective July 1, 2010. In October 2009, the Texas Utility Commission issued its order approving recovery of the 2010 energy efficiency program costs and a partial performance bonus of approximately $8 million, plus carrying costs, but disallowed a recovery of a performance bonus of $2 million on

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approximately $10 million in 2008 energy efficiency costs expended pursuant to the terms of a settlement agreement in a prior rate case. CenterPoint Houston began collecting the approved amounts in July 2010. CenterPoint Houston appealed the denial of the full 2008 performance bonus to the 98th district court in Travis County, Texas. In October 2010, the district court upheld the Texas Utility Commission’s decision. In February 2011, CenterPoint Houston appealed the district court’s judgment to the Texas 3rd Court of Appeals at Austin, Texas, where the case remains pending.

In April 2010, CenterPoint Houston filed an application with the Texas Utility Commission seeking approval of certain estimated 2011 energy efficiency programs, an energy efficiency performance bonus for 2009 programs, and recovery of revenue losses related to the implementation of the 2009 energy efficiency program totaling approximately $14.4 million. The application sought to begin recovery of these costs through a surcharge beginning
in January 2011. In November 2010, the Texas Utility Commission issued its order approving recovery of the 2011 energy efficiency program costs and a partial performance bonus of approximately $11 million, but disallowed a recovery of a performance bonus of $2 million on the 2009 energy efficiency costs expended pursuant to the terms of the settlement agreement referenced above. The Texas Utility Commission further concluded that it does not have statutory authority to permit recovery of the approximately $1.4 million in lost revenue associated with 2009 energy efficiency programs. CenterPoint Houston began collecting the approved amounts in January 2011, but has appealed the denial of the full 2009 performance bonus and lost revenue to the 201st district court in Travis County, Texas, where the case remains pending.

Rulemaking Proceedings.
In January 2010, the Texas Utility Commission published proposed amendments to its energy efficiency rule. During the statutory comment period, CenterPoint Houston urged, as part of the rule amendments, the adoption of a lost revenue recovery mechanism to keep whole the utilities participating in the required energy efficiency programs. In July 2010, the Texas Utility Commission adopted amendments to its energy efficiency program rules, but concluded it did not have the statutory authority to permit recovery of lost revenue associated with energy efficiency programs. CenterPoint Houston has appealed the rule to the Texas 3rd Court of Appeals at Austin, Texas on the basis that it is invalid as amended because it does not permit lost revenue recovery.

In October 2010, amended rules of the Texas Utility Commission relating to the Transmission Cost Recovery Factor (TCRF) became effective. The amended rules permit a distribution service provider (DSP) such as CenterPoint Houston to defer for future recovery increases in transmission costs that are charged to the DSP by transmission service providers (TSPs) during the interim period before the DSP is authorized to request an adjustment to its TCRF. The TCRF permits a DSP to recover from REPs approved changes in transmission charges from TSPs, but the TCRF can be changed by the DSP only twice per year on application to the Texas Utility Commission. The revised rules permit DSPs to obtain full recovery of the increased transmission charges.

Natural Gas Distribution

In almost all communities in which Gas Operations provides natural gas distribution services, it operates under franchises, certificates or licenses obtained from state and local authorities. The original terms of the franchises, with various expiration dates, typically range from 10 to 30 years, although franchises in Arkansas are perpetual. Gas Operations expects to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive.

Substantially all of Gas Operations is subject to cost-of-service regulation by the relevant state public utility commissions and, in Texas, by the Railroad Commission of Texas (Railroad Commission) and those municipalities served by Gas Operations that have retained original jurisdiction.

Texas.
In March 2008, Gas Operations filed a request to change its rates with the Railroad Commission and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston. In 2008, the Railroad Commission approved the implementation of rates increasing annual revenues by approximately $3.5 million. The approved rates were contested by a coalition of nine cities in an appeal to the 353rd district court in Travis County, Texas. In January 2010, that court reversed the Railroad Commission’s order in part and remanded the matter to the Railroad Commission. In its final judgment, the court ruled that the Railroad Commission lacked authority to impose the approved cost of service adjustment mechanism in both those nine cities and in those areas in which the Railroad Commission has original jurisdiction.

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The Railroad Commission and Gas Operations have appealed the court’s ruling on the cost of service adjustment mechanism to the 3
rd
Court of Appeals at Austin, Texas. Oral arguments were held in February 2011. The cost of service adjustment was initially effective for three successive years ending in calendar year 2010, but would automatically renew for successive three-year periods unless Gas Operations or the regulatory authority having original jurisdiction gave written notice to discontinue the adjustment mechanism by February 1, 2011. Certain cities that agreed to the initial implementation notified Gas Operations by February 1, 2011 of their desire to discontinue the adjustment mechanism. Gas Operations will continue the cost of service adjustments for the remaining areas.

In July 2009, Gas Operations filed a request to change its rates with the Railroad Commission and the 29 cities in its Houston service territory, consisting of approximately 940,000 customers in and around Houston. The request sought to establish uniform rates, charges and terms and conditions of service for the cities and environs of the
Houston service territory. As finally submitted to the Railroad Commission and the cities, the proposed new rates would have resulted in an overall increase in annual revenue of $20.4 million, excluding carrying costs of approximately $2 million on its gas inventory, and would be subject to an annual cost of service adjustment. In January 2010, Gas Operations withdrew its request for an annual cost of service adjustment mechanism due to the uncertainty caused by the court’s ruling in the above-mentioned Texas Coast appeal. In February 2010, the Railroad Commission issued its decision authorizing a revenue increase of $5.1 million annually, reflecting reduced depreciation rates as well as adjustments to pension and other employee benefits, accumulated deferred income taxes and other items. The Railroad Commission also approved a surcharge of $0.9 million per year to recover Hurricane Ike costs over three years. These rates went into effect in March 2010. Gas Operations and other parties are seeking judicial review of the Railroad Commission’s decision in the 261st District Court in Travis County, Texas.

In December 2010, Gas Operations filed a request to change its rates with the Railroad Commission and the 66 cities in its South Texas service territory, consisting of approximately 137,000 customers. The request seeks an increase in base revenues of approximately $6.5 million, based on an 11% return on equity and a capital structure of 56% equity and 44% debt. A decision from the Railroad Commission is anticipated in the summer of 2011.

In February 2011, the Railroad Commission approved a rule requiring evaluation of natural gas distribution systems and submission of a plan by August 2011 to address the risks identified. Each operator's risk-based program is to be developed in conjunction with the recently enacted federal regulations regarding integrity management for distribution system operators. The rule allows Gas Operations to record a regulatory asset to account for amounts spent to comply with the rule and to accrue carrying costs. The determination of the reasonableness and necessity of any investment or expense will be determined in the next rate case. We do not anticipate compliance with this rule will cause a material increase in capital expenditures or operating costs.

The Texas legislature periodically reviews the performance of and the need for government agencies such as the Railroad Commission under the Texas Sunset law. In January 2011, the Sunset Commission established by the legislature issued its report on the Railroad Commission for consideration by the Texas legislature during its 2011 session. The recommendations by the Sunset Commission include replacing the three-member elected Railroad Commission with a single elected Commissioner, and moving hearings currently conducted at the Railroad Commission to the State Office of Administrative Hearings. The Sunset Commission also recommended changing the name of the Railroad Commission to the “Texas Oil and Gas Commission.” We cannot predict what action, if any, the Texas legislature may take with respect to those recommendations.

Minnesota.
In November 2008, Gas Operations filed a request with the Minnesota Public Utilities Commission (MPUC) to increase its rates for utility distribution service by $59.8 million annually. In addition, Gas Operations sought an adjustment mechanism that would annually adjust rates to reflect changes in use per customer. In December 2008, the MPUC accepted the case and approved an interim rate increase of $51.2 million, which became effective on January 2, 2009, subject to refund. In January 2010, the MPUC issued its decision authorizing a revenue increase of $40.8 million per year, with an overall rate of return of 8.09% (10.24% return on equity). The MPUC also authorized Gas Operations to implement a pilot program for residential and small volume commercial customers that is intended to decouple gas revenues from customers’ natural gas usage. In July 2010, Gas Operations implemented the revised rates approved by the MPUC and in August 2010 completed the refund to customers of the difference between the amounts finally approved by the MPUC and interim amounts collected. In October 2010, the MPUC approved a request by Gas Operations to implement a rate adjustment to increase its

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conservation improvement plan (CIP) recovery rate from $9.7 million to $23.2 million annually. In addition, the MPUC approved a $1.4 million incentive based on Gas Operations’ 2009 CIP program.

Department of Transportation

In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (2006 Act), which reauthorized the programs adopted under the Pipeline Safety Improvement Act of 2002 (2002 Act). These programs included several requirements related to ensuring pipeline safety, and a requirement to assess the integrity of pipeline transmission facilities in areas of high population concentration. Under the 2002 Act, remediation activities are to be performed over a 10-year period. Our pipeline subsidiaries are on schedule to comply with the timeframe mandated for completion of integrity assessment and remediation.

Pursuant to the 2006 Act, the Pipeline and Hazardous Materials Safety Administration (PHMSA) at the Department of Transportation (DOT) issued regulations, effective February 12, 2010, requiring operators of gas distribution pipelines to develop and implement integrity management programs similar to those required for gas transmission pipelines, but tailored to reflect the differences in distribution pipelines. Operators of gas distribution systems must write and implement their integrity management programs by August 2, 2011. CERC’s natural gas distribution companies are on schedule to meet this deadline.

Pursuant to the 2002 Act and the 2006 Act, PHMSA has adopted a number of rules concerning, among other things, distinguishing between gathering lines and transmission facilities, requiring certain design and construction features in new and replaced lines to reduce corrosion and requiring pipeline operators to amend existing written operations and maintenance procedures and operator qualification programs. PHMSA has also updated its reporting requirements for natural gas pipelines effective January 1, 2011.

We anticipate that compliance with these regulations and performance of the remediation activities by CERC’s interstate and intrastate pipelines and natural gas distribution companies will require increases in both capital expenditures and operating costs. The level of expenditures will depend upon several factors, including age, location and operating pressures of the facilities.

ENVIRONMENTAL MATTERS

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas pipelines and distribution systems, gas gathering and processing systems, and electric transmission and distribution systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

•

restricting the way we can handle or dispose of wastes;

•

limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions or areas inhabited by endangered species;

•

requiring remedial action to mitigate environmental conditions caused by our operations or attributable to former operations;

•

enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations; and

•

impacting the demand for our services by directly or indirectly affecting the use or price of natural gas, or the ability to extract natural gas in areas we serve in our interstate pipelines and field services businesses.

In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to:

•

construct or acquire new equipment;

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•

acquire permits for facility operations;

•

modify or replace existing and proposed equipment; and

•

clean up or decommission waste disposal areas, fuel storage and management facilities and other locations and facilities.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently
anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.

Based on current regulatory requirements and interpretations, we do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position, results of operations or cash flows. In addition, we believe that our current environmental remediation activities will not materially interrupt or diminish our operational ability. We cannot assure you, however, that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs. The following is a discussion of all material environmental and safety laws and regulations that relate to our operations. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Global Climate Change

In recent years, there has been increasing public debate regarding the potential impact on global climate change by various “greenhouse gases” (GHGs) such as carbon dioxide, a byproduct of burning fossil fuels, and methane, the principal component of the natural gas that we transport and deliver to customers. Legislation to regulate emissions of GHGs has been introduced in Congress, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. Some of the proposals would require industrial sources to meet stringent new standards that would require substantial reductions in carbon emissions. These regulations could be costly and difficult to implement. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues, such as the United Nations Climate Change Conference in Copenhagen in 2009. Also, the U.S. Environmental Protection Agency (EPA) has undertaken new efforts to collect information regarding GHG emissions and their effects. Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA proposed to expand its regulations relating to those emissions and has adopted rules imposing permitting and reporting obligations that we expect to be applicable to certain aspects of our operations. Specifically, the EPA adopted a final rule
to address permitting of methane and other GHG emissions from stationary sources under the Clean Air Act's Prevention of Significant Deterioration and Title V programs. Additionally, the EPA has issued the
“Mandatory Reporting of Greenhouse Gases Rule,” which establishes a new comprehensive scheme for reporting GHG emissions. In late 2010, the EPA finalized
new GHG reporting requirements for upstream petroleum and natural gas systems, which will be added to EPA's GHG Reporting Rule, and will require facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year to report annual GHG emissions, with the first report due on March 31, 2012. These permitting and reporting requirements could lead to further regulation of GHGs by the EPA
.

It is too early to determine whether, or in what form, further regulatory action regarding GHG emissions will be adopted or what specific impacts a new regulatory action might have on us and our subsidiaries. Although it now

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appears unlikely that new legislation regarding GHGs will be adopted in the near term, action by the EPA to impose new regulations and standards regarding GHG emissions is underway and appears likely to result in new standards and regulatory requirements. As a distributor and transporter of natural gas and consumer of natural gas in its pipeline and gathering businesses, CERC’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas. Our electric transmission and distribution business, in contrast to some electric utilities, does not generate electricity and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity. Nevertheless, CenterPoint Houston’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within its service territory. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services. Conversely, regulatory actions that effectively promote the consumption of natural gas because of its lower emissions characteristics, would be expected to beneficially affect CERC and its natural gas-related businesses. At this point in time, however, it would be speculative to try to quantify the magnitude of the impacts from possible new regulatory actions related to GHG emissions, either positive or negative, on our businesses.

To the extent climate changes occur, our businesses may be adversely impacted, though we believe any such impacts are likely to occur very gradually and hence would be difficult to quantify with specificity. To the extent global climate change results in warmer temperatures in our service territories, financial results from our natural gas distribution businesses could be adversely affected through lower gas sales, and our gas transmission and field services businesses could experience lower revenues. On the other hand, warmer temperatures in our electric service territory may increase our revenues from transmission and distribution through increased demand for electricity for cooling. Another possible climate change is more frequent and more severe weather events, such as hurricanes or tornadoes. Since many of our facilities are located along or near the Gulf Coast, increased or more severe hurricanes or tornadoes can increase our costs to repair damaged facilities and restore service to our customers. When we cannot deliver electricity or natural gas to customers or our customers cannot receive our services, our financial results can be impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs. To the extent we are unable to recover those costs, or if higher rates resulting from our recovery of such costs result in reduced demand for our services, our future financial results may be adversely impacted.

Air Emissions

Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

In 2010, the EPA adopted amendments to its regulations regarding maximum achievable control technology for stationary internal combustion engines (sometimes referred to as the RICE MACT rule) and continues to consider additional amendments. Compressors used by our Pipelines and Field Services segments are affected by these rules. Compliance with the current rules could require capital expenditures of $40 million to $50 million over the next 5 years. The estimated amount does not include costs to comply with new amendments which are expected to be proposed by the EPA for compliance by 2015. We estimate that compliance with these anticipated 2015 RICE MACT amendments as currently envisioned could require capital expenditures of $50 million to $75 million over the next 5 years. We believe, however, that our operations will not be materially adversely affected by such requirements.

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Water Discharges

Our operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remedial obligations.

Hazardous Waste

Our operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (RCRA), and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste waters produced and other wastes associated with the exploration, development or
production of crude oil and natural gas. However, these oil and gas exploration and production wastes are still regulated under state law and the less stringent non-hazardous waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that would be subject to RCRA or comparable state law requirements.

Liability for Remediation

The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for the disposal of hazardous substances at offsite locations such as landfills. Although petroleum, as well as natural gas, is excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the EPA and, in some cases, third parties to take action in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for the costs of certain health studies.

Liability for Preexisting Conditions

Manufactured Gas Plant Sites.
CERC and its predecessors operated manufactured gas plants (MGPs) in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC’s Minnesota service territory. CERC believes that it has no liability with respect to two of these sites.

At December 31, 2010, CERC had accrued $14 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRPs), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. In January 2010, as part of its Minnesota rate case decision, the MPUC eliminated the environmental expense tracker mechanism and ordered amounts previously collected from ratepayers and related carrying costs refunded to customers in 2010. Such refund was completed in August 2010. The MPUC provided for the inclusion in rates of approximately $285,000 annually to fund normal on-going remediation costs.

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CERC was not required to refund to customers the amount collected from insurance companies, $5.2 million at December 31, 2010, to be used to mitigate future environmental costs. The MPUC further gave assurance that any reasonable and prudent environmental clean-up costs CERC incurs in the future will be rate-recoverable under normal regulatory principles and procedures. This provision had no impact on earnings.

In addition to the Minnesota sites, the EPA and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC has been named as a defendant in a lawsuit filed in the United States District Court, District of Maine, under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. CERC has also been identified as a PRP by the State of Maine for a site that is a subject of the lawsuit. In June 2006, the federal district court in Maine ruled that the current owner of the site is responsible for site remediation but that an additional evidentiary hearing would be required to determine if other potentially responsible parties, including CERC, would have to contribute to that remediation. In September 2009, the federal district court granted CERC’s motion for summary judgment in the proceeding. Although it is likely that the plaintiff will pursue an appeal from that dismissal, further action will not be taken until the district court disposes of claims against other defendants in the case. CERC believes it is not liable as a former owner or operator of the site under CERCLA and applicable state statutes, and is vigorously contesting the suit and its designation as a PRP. We
and CERC do not expect the ultimate outcome to have a material adverse impact on the financial condition, results of operations or cash flows of either us or CERC.

Asbestos.
Some facilities owned by us contain or have contained asbestos insulation and other asbestos-containing materials. We or our subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by us, but most existing claims relate to facilities previously owned by our subsidiaries. We anticipate that additional claims like those received may be asserted in the future. In 2004, we sold our generating business, to which most of these claims relate, to Texas Genco LLC, which is now known as NRG Texas LP. Under the terms of the arrangements regarding separation of the generating business from us and our sale to NRG Texas LP, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by NRG Texas LP, but we have agreed to continue to defend such claims to the extent they are covered by insurance maintained by us, subject to reimbursement of the costs of such defense from NRG Texas LP. Although their ultimate outcome cannot be predicted at this time, we intend to continue vigorously contesting claims that we do not consider to have merit and do not expect, based on our experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on our financial condition, results of operations or cash flows.

Groundwater Contamination Litigation.
Predecessor entities of CERC, along with several other entities, are defendants in litigation,
St. Michel Plantation, LLC, et al, v. White, et al
., pending in civil district court in Orleans Parish, Louisiana. In the lawsuit, the plaintiffs allege that their property in Terrebonne Parish, Louisiana suffered salt water contamination as a result of oil and gas drilling activities conducted by the defendants. Although a predecessor of CERC held an interest in two oil and gas leases on a portion of the property at issue, neither it nor any other CERC entities drilled or conducted other oil and gas operations on those leases. In January 2009, CERC and the plaintiffs reached agreement on the terms of a settlement that, if ultimately approved by the Louisiana Department of Natural Resources, is expected to resolve this litigation. We and CERC do not expect the outcome of this litigation to have a material adverse impact on the financial condition, results of operations or cash flows of either us or CERC.

Other Environmental.
From time to time we have received notices from regulatory authorities or others regarding our status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, we have been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, we do not expect, based on our experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on our financial condition, results of operations or cash flows.

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EMPLOYEES

As of December 31, 2010, we had 8,843 full-time employees. The following table sets forth the number of our employees by business segment:

Business Segment

Number

Number

Represented

by Unions or

Other Collective

Bargaining Groups

Electric Transmission & Distribution

2,813

1,270

Natural Gas Distribution

3,586

1,362

Competitive Natural Gas Sales and Services

133

—

Interstate Pipelines

728

—

Field Services

278

—

Other Operations

1,305

—

Total

8,843

2,632

As of December 31, 2010, approximately 30% of our employees are subject to collective bargaining agreements. Collective bargaining agreements with two of our unions, the Gas Workers Union Local No. 340 and the International Brotherhood of Electrical Workers Local 949, that collectively represent approximately 7% of our employees are
scheduled to expire in 2011. We have a good relationship with these bargaining units and expect to negotiate new agreements in 2011.

EXECUTIVE OFFICERS

(as of February 15, 2011)

Name

Age

Title

David M. McClanahan

61

President and Chief Executive Officer and Director

Scott E. Rozzell

61

Executive Vice President, General Counsel and Corporate

Secretary

Gary L. Whitlock

61

Executive Vice President and Chief Financial Officer

C. Gregory Harper

46

Senior Vice President and Group President, CenterPoint

Energy Pipelines and Field Services

Thomas R. Standish

61

Senior Vice President and Group President — Regulated Operations

David M. McClanahan
has been President and Chief Executive Officer and a director of CenterPoint Energy since September 2002. He served as Vice Chairman of Reliant Energy, Incorporated (Reliant Energy) from October 2000 to September 2002 and as President and Chief Operating Officer of Reliant Energy’s Delivery Group from April 1999 to September 2002. He previously served as Chairman of the Board of Directors of ERCOT, Chairman of the Board of the University of St. Thomas in Houston and Chairman of the Board of the American Gas Association. He currently serves on the boards of the Edison Electric Institute and the American Gas Association.

Scott E. Rozzell
has served as Executive Vice President, General Counsel and Corporate Secretary of CenterPoint Energy since September 2002. He served as Executive Vice President and General Counsel of the Delivery Group of Reliant Energy from March 2001 to September 2002. Before joining Reliant Energy in 2001, Mr. Rozzell was a senior partner in the law firm of Baker Botts L.L.P. He currently serves on the Board of Directors of the Association of Electric Companies of Texas.

Gary L. Whitlock
has served as Executive Vice President and Chief Financial Officer of CenterPoint Energy since September 2002. He served as Executive Vice President and Chief Financial Officer of the Delivery Group of Reliant Energy from July 2001 to September 2002. Mr. Whitlock served as the Vice President, Finance and Chief Financial Officer of Dow AgroSciences, a subsidiary of The Dow Chemical Company, from 1998 to 2001.

C. Gregory Harper
has served as Senior Vice President and Group President of CenterPoint Energy Pipelines and Field Services since December 2008. Before joining CenterPoint Energy in 2008, Mr. Harper served as President, Chief Executive Officer and as a Director of Spectra Energy Partners, LP from March 2007 to December

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2008. From January 2007 to March 2007, Mr. Harper was Group Vice President of Spectra Energy Corp., and he was Group Vice President of Duke Energy from January 2004 to December 2006.
Mr. Harper served as Senior Vice President of Energy Marketing and Management for Duke Energy North America from January 2003 until January 2004 and Vice President of Business Development for Duke Energy Gas Transmission and Vice President of East Tennessee Natural Gas, LLC from March 2002 until January 2003. He currently serves on the Board of Directors of the Interstate Natural Gas Association of America.

Thomas R. Standish
has served as Senior Vice President and Group President-Regulated Operations of CenterPoint Energy since August 2005, having previously served as Senior Vice President and Group President and Chief Operating Officer of CenterPoint Houston from June 2004 to August 2005 and as President and Chief Operating Officer of CenterPoint Houston from August 2002 to June 2004. He served as President and Chief Operating Officer for both electricity and natural gas for Reliant Energy’s Houston area from 1999 to August 2002.

We are a holding company that conducts all of our business operations through subsidiaries, primarily CenterPoint Houston and CERC. The following, along with any additional legal proceedings identified or incorporated by reference in Item 3 of this report, summarizes the principal risk factors associated with the businesses conducted by each of these subsidiaries:

Following the exhaustion of all judicial appeals in its true-up proceeding, CenterPoint Houston may lose certain tax benefits and/or may not recover the full amount of its true-up request. Such a result could have an adverse impact on CenterPoint Houston’s results of operations, financial condition and cash flows.

In March 2004, CenterPoint Houston filed its true-up application with the Texas Utility Commission, requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas electric restructuring law. In December 2004, the Texas Utility Commission issued its True-Up Order allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and provided for adjustment of the amount to be recovered to include interest on the balance until recovery, along with the principal portion of additional EMCs returned to customers after August 31, 2004 and certain other adjustments.

CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, that court issued its judgment on the various appeals. In its judgment, the district court:

•

reversed the Texas Utility Commission’s ruling that had denied CenterPoint Houston recovery of a portion of the capacity auction true-up amounts;

•

reversed the Texas Utility Commission’s ruling that precluded CenterPoint Houston from recovering the interest component of the EMCs paid to REPs; and

•

affirmed the True-Up Order in all other respects.

The district court’s decision would have had the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston’s initial request.

CenterPoint Houston and other parties appealed the district court’s judgment to the Texas Third Court of Appeals, which issued its decision in December 2007. In its decision, the court of appeals:

•

reversed the district court’s judgment to the extent it restored the capacity auction true-up amounts;

•

reversed the district court’s judgment to the extent it upheld the Texas Utility Commission’s decision to allow CenterPoint Houston to recover EMCs paid to RRI;

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•

ordered that the tax normalization issue described below be remanded to the Texas Utility Commission as requested by the Texas Utility Commission; and

•

affirmed the district court’s judgment in all other respects.

In April 2008, the court of appeals denied all motions for rehearing and reissued substantially the same opinion as it had rendered in December 2007.

In June 2008, CenterPoint Houston petitioned the Texas Supreme Court for review of the court of appeals decision. In its petition, CenterPoint Houston seeks reversal of the parts of the court of appeals decision that (i) denied recovery of EMCs paid to RRI, (ii) denied recovery of the capacity auction true-up amounts allowed by the district court, (iii) affirmed the Texas Utility Commission’s rulings that denied recovery of approximately $378 million related to depreciation and (iv) affirmed the Texas Utility Commission’s refusal to permit CenterPoint Houston to utilize the partial stock valuation methodology for determining the market value of its former generation assets. Two other petitions for review were filed with the Texas Supreme Court by other parties to the appeal. In those petitions parties contend that (i) the Texas Utility Commission was without authority to fashion the methodology it used for valuing the former generation assets after it had determined that CenterPoint Houston could not use the partial stock valuation method, (ii) in fashioning the method it used for valuing the former generating assets, the Texas Utility Commission deprived parties of their due process rights and an opportunity to be heard, (iii) the net book value of the generating assets should have been adjusted downward due to the impact of a purchase
option that had been granted to RRI, (iv) CenterPoint Houston should not have been permitted to recover construction work in progress balances without proving those amounts in the manner required by law and (v) the Texas Utility Commission was without authority to award interest on the capacity auction true up award.

In June 2009, the Texas Supreme Court granted the petitions for review of the court of appeals decision. Oral argument before the court was held in October 2009.

To reflect the impact of the True-Up Order, in 2004 and 2005, we recorded a net after-tax extraordinary loss of $947 million. No amounts related to the district court’s judgment or the decision of the court of appeals have been recorded in our consolidated financial statements. However, if the court of appeals decision is not reversed or modified as a result of further review by the Texas Supreme Court, we anticipate that we would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue described below, but could range from $190 million to $440 million (pre-tax) plus interest subsequent to December 31, 2010.

In the True-Up Order, the Texas Utility Commission reduced CenterPoint Houston’s stranded cost recovery by approximately $146 million, which was included in the extraordinary loss discussed above, to reflect the present value of certain deferred tax benefits associated with its former electric generation assets. We believe that the Texas Utility Commission based its order on proposed regulations issued by the IRS in March 2003 that would have allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of ADITC and EDFIT back to customers. However, the IRS subsequently withdrew those proposed normalization regulations and, in March 2008, adopted final regulations that would not permit utilities like CenterPoint Houston to pass the tax benefits back to customers without creating normalization violations. In addition, we received a PLR from the IRS in August 2007, prior to adoption of the final regulations, that confirmed that the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations with respect to the ADITC and EDFIT.

If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require us to pay an amount equal to CenterPoint Houston’s unamortized ADITC balance as of the date that the normalization violation is deemed to have occurred. In addition, the IRS could deny CenterPoint Houston the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. Such treatment, if required by the IRS, could have a material adverse impact on our results of operations, financial condition and cash flows in addition to any potential loss resulting from final resolution of the True-Up Order. Following the adoption by the IRS of the final regulations described above, the Texas Utility Commission requested, and the court of appeals ordered, that this issue be remanded to that commission for further consideration. No party has challenged

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that order by the court of appeals although the Texas Supreme Court has the authority to consider all aspects of the rulings above, not just those challenged specifically by the appellants. We and CenterPoint Houston will continue to pursue a favorable resolution of this issue through the appellate and administrative process. Although the Texas Utility Commission has requested that this issue be remanded to it by the courts and has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

CenterPoint Houston’s receivables are concentrated in a small number of REPs, and any delay or default in payment could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations.

CenterPoint Houston’s receivables from the distribution of electricity are collected from REPs that supply the electricity CenterPoint Houston distributes to their customers. As of December 31, 2010, CenterPoint Houston did business with 99 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for CenterPoint Houston’s services or could cause them to delay such payments. CenterPoint Houston depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to a provider of last resort if a REP cannot make timely payments. Applicable Texas Utility Commission regulations significantly limit the extent to which CenterPoint Houston can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and thus remains at risk for payments not made prior to the shift to the provider of last resort. The Texas Utility Commission revised its
regulations in 2009 to (i) increase the financial qualifications from REPs that began selling power after January 1, 2009, and (ii) authorize utilities to defer bad debts resulting from defaults by REPs for recovery in a future rate case. A subsidiary of NRG Energy, Inc., NRG Retail, (which acquired the Texas retail business of RRI) and its subsidiaries are together considered the largest REP in CenterPoint Houston’s service territory. Approximately 33% of CenterPoint Houston’s $138 million in billed receivables from REPs at December 31, 2010 was owed by subsidiaries of NRG Retail and approximately 13% of the $138 million in billed receivables was owed by subsidiaries of TXU Energy Retail. Any delay or default in payment by REPs could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations and claims might be made by creditors involving payments CenterPoint Houston had received from such REP.

Rate regulation of CenterPoint Houston’s business may delay or deny CenterPoint Houston’s ability to earn a reasonable return and fully recover its costs.

CenterPoint Houston’s rates are regulated by certain municipalities and the Texas Utility Commission based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CenterPoint Houston is allowed to charge may not match its expenses at any given time. The regulatory process by which rates are determined may not always result in rates that will produce full recovery of CenterPoint Houston’s costs and enable CenterPoint Houston to earn a reasonable return on its invested capital.

Disruptions at power generation facilities owned by third parties could interrupt CenterPoint Houston’s sales of transmission and distribution services.

CenterPoint Houston transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. CenterPoint Houston does not own or operate any power generation facilities. If power generation is disrupted or if power generation capacity is inadequate, CenterPoint Houston’s sales of transmission and distribution services may be diminished or interrupted, and its results of operations, financial condition and cash flows could be adversely affected.

CenterPoint Houston’s revenues and results of operations are seasonal.

A significant portion of CenterPoint Houston’s revenues is derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of such REP. Thus, CenterPoint Houston’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues being higher during the warmer months.

Rate regulation of CERC’s business may delay or deny CERC’s ability to earn a reasonable return and fully recover its costs.

CERC’s rates for Gas Operations are regulated by certain municipalities and state commissions, and for its interstate pipelines by the FERC, based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CERC is allowed to charge may not match its expenses at any given time. The regulatory process in which rates are determined may not always result in rates that will produce full recovery of CERC’s costs and enable CERC to earn a reasonable return on its invested capital.

CERC’s businesses must compete with alternate energy sources, which could result in CERC marketing less natural gas, and its interstate pipelines and field services businesses must compete directly with others in the transportation, storage, gathering, treating and processing of natural gas, which could lead to lower prices and reduced volumes, either of which could have an adverse impact on CERC’s results of operations, financial condition and cash flows.

CERC competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and marketers also compete directly with CERC for natural gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass CERC’s facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by CERC as a result of competition may have an adverse impact on CERC’s results of operations, financial condition and cash flows.

CERC’s two interstate pipelines and its gathering systems compete with other interstate and intrastate pipelines and gathering systems in the transportation and storage of natural gas. The principal elements of competition are rates, terms of service, and flexibility and reliability of service. They also compete indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price, but recently, environmental considerations have grown in importance when consumers consider alternative forms of energy. The actions of CERC’s competitors could lead to lower prices, which may have an adverse impact on CERC’s results of operations, financial condition and cash flows. Additionally, any reduction in the volume of natural gas transported or stored may have an adverse impact on CERC’s results of operations, financial condition and cash flows.

CERC’s natural gas distribution and competitive natural gas sales and services businesses are subject to fluctuations in natural gas prices, which could affect the ability of CERC’s suppliers and customers to meet their obligations or otherwise adversely affect CERC’s liquidity and results of operations.

CERC is subject to risk associated with changes in the price of natural gas. Increases in natural gas prices might affect CERC’s ability to collect balances due from its customers and, for Gas Operations, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into CERC’s tariff rates. In addition, a sustained period of high natural gas prices could (i) apply downward demand pressure on natural gas consumption in the areas in which CERC operates thereby resulting in decreased sales and transportation volumes and revenues and (ii) increase the risk that CERC’s suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase CERC’s working capital requirements by increasing the investment that must be made in order to maintain natural gas inventory levels. Additionally, a decrease in natural gas prices could increase the amount of collateral that CERC must provide under its hedging arrangements.

A decline in CERC’s credit rating could result in CERC’s having to provide collateral under its shipping or hedging arrangements or in order to purchase natural gas.

If CERC’s credit rating were to decline, it might be required to post cash collateral under its shipping or hedging arrangements or in order to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when CERC was experiencing significant working capital requirements or

The revenues and results of operations of CERC’s interstate pipelines and field services businesses are subject to fluctuations in the supply and price of natural gas and natural gas liquids and regulatory and other issues impacting our customers’ production decisions.

CERC’s interstate pipelines and field services businesses largely rely on natural gas sourced in the various supply basins located in the Mid-continent region of the United States. The level of drilling and production activity in these regions is dependent on economic and business factors beyond our control. The primary factor affecting both the level of drilling activity and production volumes is natural gas pricing. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the regions served by our gathering and pipeline transportation systems and our natural gas treating and processing activities. A sustained decline could also
lead producers to shut in production from their existing wells. Other factors that impact production decisions include the level of production costs relative to other available production, producers’ access to needed capital and the cost of that capital, access to drilling rigs, the ability of producers to obtain necessary drilling and other governmental permits and regulatory changes. Regulatory changes include the potential for more restrictive rules governing the use of hydraulic fracturing, a process used in the extraction of natural gas from shale reservoir formations, and the use of groundwater in that process. Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves or to shut in production from existing reserves. To the extent the availability of this supply is substantially reduced, it could have an adverse effect on CERC’s results of operations, financial condition and cash flows.

CERC’s revenues from these businesses are also affected by the prices of natural gas and natural gas liquids (NGLs). NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. The markets and prices for natural gas, NGLs and crude oil depend upon factors beyond our control. These factors include supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors.

CERC’s revenues and results of operations are seasonal.

A substantial portion of CERC’s revenues is derived from natural gas sales and transportation. Thus, CERC’s revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months.

The actual cost of pipelines and gathering systems under construction, future pipeline, gathering and treating systems and related compression facilities may be significantly higher than CERC had planned.

Subsidiaries of CERC Corp. have been recently involved in significant pipeline and gathering construction projects and, depending on available opportunities, may, from time to time, be involved in additional significant pipeline construction and gathering and treating system projects in the future. The construction of new pipelines, gathering and treating systems and related compression facilities may require the expenditure of significant amounts of capital, which may exceed CERC’s estimates. These projects may not be completed at the planned cost, on schedule or at all. The construction of new pipeline, gathering, treating or compression facilities is subject to construction cost overruns due to labor costs, costs of equipment and materials such as steel and nickel, labor shortages or delays, weather delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. As a result, there is the risk that the new facilities may not be able to achieve CERC’s expected investment return, which could adversely affect CERC’s financial condition, results of operations or cash flows.

29

The states in which CERC provides regulated local gas distribution may, either through legislation or rules, adopt restrictions similar to or broader than those under the Public Utility Holding Company Act of 1935 regarding organization, financing and affiliate transactions that could have significant adverse impacts on CERC’s ability to operate.

The Public Utility Holding Company Act of 1935, to which we and our subsidiaries were subject prior to its repeal in the Energy Policy Act of 2005, provided a comprehensive regulatory structure governing the organization, capital structure, intracompany relationships and lines of business that could be pursued by registered holding companies and their member companies. Following repeal of that Act, proposals have been put forth in some of the states in which CERC does business that have sought to expand the state regulatory frameworks to give state regulatory authorities increased jurisdiction and scrutiny over similar aspects of the utilities that operate in their states. Some of these frameworks attempt to regulate financing activities, acquisitions and divestitures, and arrangements between the utilities and their affiliates, and to restrict the level of non-utility business that can be conducted within the holding company structure. Additionally they may impose record keeping, record access, employee training and reporting requirements related to affiliate transactions and reporting in the event of certain downgrading of the utility’s bond rating.

These regulatory frameworks could have adverse effects on CERC’s ability to conduct its utility operations, to finance its business and to provide cost-effective utility service. In addition, if more than one state adopts restrictions on similar activities, it may be difficult for CERC and us to comply with competing regulatory requirements.

Risk Factors Associated with Our Consolidated Financial Condition

If we are unable to arrange future financings on acceptable terms, our ability to
refinance existing indebtedness could be limited.

As of December 31, 2010, we had $9.5 billion of outstanding indebtedness on a consolidated basis, which includes $2.8 billion of non-recourse transition and system restoration bonds. As of December 31, 2010, approximately $1.1 billion principal amount of this debt is required to be paid through 2013. This amount excludes (i) $550 million principal amount of CERC Corp. senior notes that were repaid at their maturity in February 2011 with proceeds from the issuance in January 2011 of $550 million principal amount of CERC Corp. senior notes maturing subsequent to 2013, (ii) $397 million principal amount of CERC Corp. 7.875% senior notes due 2013 that were exchanged in January 2011 for CERC Corp. senior notes maturing subsequent to 2013 and (iii) principal repayments of approximately $920 million on transition and system restoration bonds, for which a dedicated revenue stream exists. Our future financing activities may be significantly affected by, among other things:

•

the resolution of the true-up proceedings, including, in particular, the results of appeals to the Texas Supreme Court regarding rulings obtained to date;

our exposure to GenOn in connection with its indemnification obligations arising in connection with its separation from us;

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•

incremental collateral that may be required due to regulation of derivatives; and

•

provisions of relevant tax and securities laws.

As of December 31, 2010, CenterPoint Houston had approximately $2.5 billion aggregate principal amount of general mortgage bonds outstanding under the General Mortgage, (a) including $290 million held in trust to secure pollution control bonds that are not reflected on our consolidated financial statements because we are both the obligor on the bonds and the owner of the bonds, (b) an additional approximately $237 million held in trust to secure pollution control bonds for which we are obligated and (c) approximately $229 million held in trust to secure pollution control bonds for which CenterPoint Houston is obligated. Additionally, CenterPoint Houston had approximately $253 million aggregate principal amount of first mortgage bonds outstanding under the Mortgage, including approximately $151 million held in trust to secure certain pollution control bonds for which we are obligated. CenterPoint Houston may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $2.3 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2010. However, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

Our current credit ratings are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Future Sources and Uses of Cash — Impact on Liquidity of a Downgrade in Credit Ratings” in Item 7 of Part II of this report. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to access capital on acceptable terms.

As a holding company with no operations of our own, we will depend on distributions from our subsidiaries to meet our payment obligations, and provisions of applicable law or contractual restrictions could limit the amount of those distributions.

We derive all our operating income from, and hold all our assets through, our subsidiaries. As a result, we will depend on distributions from our subsidiaries in order to meet our payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit our subsidiaries’ ability to make payments or other distributions to us, and our subsidiaries could agree to contractual restrictions on their ability to make distributions.

Our right to receive any assets of any subsidiary, and therefore the right of our creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if we were a creditor of any subsidiary, our rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by us.

The use of derivative contracts by us and our subsidiaries in the normal course of business could result in financial losses that could negatively impact our results of operations and those of our subsidiaries.

We and our subsidiaries use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity, weather and financial market risks. We and our subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

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Risks Common to Our Businesses and Other Risks

We are subject to operational and financial risks and liabilities arising from environmental laws and regulations.

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas pipelines and distribution systems, gas gathering and processing systems, and electric transmission and distribution systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

•

restricting the way we can handle or dispose of wastes;

•

limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;

•

requiring remedial action to mitigate environmental conditions caused by our operations, or attributable to former operations;

•

enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations; and

•

impacting the demand for our services by directly or indirectly affecting the use or price of natural gas, or the ability to extract natural gas in areas we serve in our interstate pipelines and field services businesses.

In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to:

•

construct or acquire new equipment;

•

acquire permits for facility operations;

•

modify or replace existing and proposed equipment; and

•

clean up or decommission waste disposal areas, fuel storage and management facilities and other locations and facilities.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.

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In common with other companies in its line of business that serve coastal regions, CenterPoint Houston does not have insurance covering its transmission and distribution system, other than substations, because CenterPoint Houston believes it to be cost prohibitive. In the future, CenterPoint Houston may not be able to recover the costs incurred in restoring its transmission and distribution properties following hurricanes or other natural disasters through issuance of storm restoration bonds or a change in its regulated rates or otherwise, or any such recovery may not be timely granted. Therefore, CenterPoint Houston may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows.

We, CenterPoint Houston and CERC could incur liabilities associated with businesses and assets that we have transferred to others.

Under some circumstances, we, CenterPoint Houston and CERC could incur liabilities associated with assets and businesses we, CenterPoint Houston and CERC no longer own. These assets and businesses were previously owned by Reliant Energy, Incorporated (Reliant Energy), a predecessor of CenterPoint Houston, directly or through subsidiaries and include:

•

merchant energy, energy trading and REP businesses transferred to RRI or its subsidiaries in connection with the organization and capitalization of RRI prior to its initial public offering in 2001; and

In connection with the organization and capitalization of RRI, that company and its subsidiaries assumed liabilities associated with various assets and businesses Reliant Energy transferred to them. RRI also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston and CERC, with respect to liabilities associated with the transferred assets and businesses. These indemnity provisions were intended to place sole financial responsibility on RRI and its subsidiaries for all liabilities associated with the current and historical businesses and operations of RRI, regardless of the time those liabilities arose. If GenOn were unable to satisfy a liability that has been so assumed in circumstances in which Reliant Energy and its subsidiaries were not released from the liability in connection with the transfer, we, CenterPoint Houston or CERC could be responsible for satisfying the liability.

In May 2009, RRI sold its Texas retail business to NRG Retail, a subsidiary of NRG Energy, Inc. In December 2010, Mirant Corporation merged with and became a wholly owned subsidiary of RRI (then known as RRI Energy, Inc.) and RRI changed its name from RRI Energy, Inc. to GenOn Energy, Inc. Neither the sale of the retail business nor the merger with Mirant Corporation alters GenOn’s contractual obligations to indemnify us and our subsidiaries, including CenterPoint Houston, for certain liabilities, including their indemnification obligations regarding certain litigation, nor does it affect the terms of existing guaranty arrangements for certain GenOn gas transportation contracts.

Prior to the distribution of our ownership in RRI to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI (now GenOn) agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guaranties for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties based on an annual calculation, with any required collateral to be posted each December. The undiscounted maximum potential payout of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately $112 million as of December 31, 2010. Market conditions in the fourth quarter of 2010 required posting of security under the agreement, and GenOn posted approximately $7 million in collateral in December 2010. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, collateral provided as security may be insufficient to satisfy CERC’s obligations.

33

GenOn’s unsecured debt ratings are currently below investment grade. If GenOn were unable to meet its obligations, it would need to consider, among various options, restructuring under the bankruptcy laws, in which event GenOn might not honor its indemnification obligations and claims by GenOn’s creditors might be made against us as its former owner.

Reliant Energy and RRI (GenOn’s predecessors) are named as defendants in a number of lawsuits arising out of sales of natural gas in California and other markets. Although these matters relate to the business and operations of GenOn, claims against Reliant Energy have been made on grounds that include liability of Reliant Energy as a controlling shareholder of GenOn’s predecessor. We, CenterPoint Houston or CERC could incur liability if claims in one or more of these lawsuits were successfully asserted against us, CenterPoint Houston or CERC and indemnification from GenOn were determined to be unavailable or if GenOn were unable to satisfy indemnification obligations owed with respect to those claims.

In connection with the organization and capitalization of Texas Genco, Reliant Energy and Texas Genco entered into a separation agreement in which Texas Genco assumed liabilities associated with the electric generation assets Reliant Energy transferred to it. Texas Genco also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston, with respect to liabilities associated with the transferred assets and businesses. In many cases the liabilities assumed were obligations of CenterPoint Houston, and CenterPoint Houston was not released by third parties from these liabilities. The indemnity provisions were intended generally to place sole financial responsibility on Texas Genco and its subsidiaries for all liabilities associated with the current and historical businesses and operations of Texas Genco,
regardless of the time those liabilities arose. If Texas Genco were unable to satisfy a liability that had been so assumed or indemnified against, and provided we or Reliant Energy had not been released from the liability in connection with the transfer, CenterPoint Houston could be responsible for satisfying the liability.

In connection with our sale of Texas Genco to a third party, the separation agreement was amended to provide that Texas Genco would no longer be liable for, and we would assume and agree to indemnify Texas Genco against, liabilities that Texas Genco originally assumed in connection with its organization to the extent, and only to the extent, that such liabilities are covered by certain insurance policies held by us. Texas Genco and its related businesses now operate as subsidiaries of NRG Energy, Inc.

We or our subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by us, but most existing claims relate to facilities previously owned by our subsidiaries but currently owned by NRG Texas LP. We anticipate that additional claims like those received may be asserted in the future. Under the terms of the arrangements regarding separation of the generating business from us and its sale to NRG Texas LP, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by NRG Texas LP, but we have agreed to continue to defend such claims to the extent they are covered by insurance maintained by us, subject to reimbursement of the costs of such defense by NRG Texas LP.

The unsettled conditions in the global financial system may have impacts on our business, liquidity and financial condition that we currently cannot predict.

The continued unsettled conditions in the global financial system may have an impact on our business, liquidity and financial condition. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our liquidity and flexibility to react to changing economic and business conditions. In addition, the cost of debt financing and the proceeds of equity financing may be materially adversely impacted by these market conditions. Defaults of lenders in our credit facilities, should they further occur, could adversely affect our liquidity. Capital market turmoil was reflected in significant reductions in equity market valuations in 2008, which significantly reduced the value of assets of our pension plan. These reductions increased non-cash pension expense in 2009 and may impact liquidity if contributions are made to offset reduced asset values.

In addition to the credit and financial market issues, national and local recessionary conditions may impact our business in a variety of ways. These include, among other things, reduced customer usage, increased customer default rates and wide swings in commodity prices.

34

Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for our services.

Legislation to regulate emissions of GHGs has been introduced in Congress, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues, such as the United Nations Climate Change Conference in Copenhagen in 2009. Also, the EPA has undertaken new efforts to collect information regarding GHG emissions and their effects. Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA proposed to expand its regulations relating to those emissions and has adopted rules imposing permitting and reporting obligations that we expect to be applicable to certain of our operations. The results of the permitting and reporting requirements could lead to further regulation of these GHGs by the EPA It is too early to determine whether, or in what form, further regulatory action regarding GHG emissions will be adopted or what specific impacts a new regulatory action might have on us and our subsidiaries. Action by the EPA to impose new regulations and standards regarding GHG emissions is underway and appears likely to result in new standards and regulatory requirements. As a distributor and transporter of natural gas and consumer of natural gas in its pipeline and gathering businesses, CERC’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas. Our electric transmission and distribution business, in contrast to some electric utilities, does not
generate electricity and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity. Nevertheless, CenterPoint Houston’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within its service territory. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services.

Climate changes could result in more frequent severe weather events which could affect the results of operations of our businesses.

To the extent climate changes occur, our businesses may be adversely impacted, though we believe any such impacts are likely to occur very gradually and hence would be difficult to quantify with specificity. To the extent global climate change results in warmer temperatures in our service territories, financial results from our natural gas distribution businesses could be adversely affected through lower gas sales, and our gas transmission and field services businesses could experience lower revenues. Another possible climate change is more frequent and more severe weather events, such as hurricanes or tornadoes. Since many of our facilities are located along or near the Gulf Coast, increased or more severe hurricanes or tornadoes can increase our costs to repair damaged facilities and restore service to our customers. When we cannot deliver electricity or natural gas to customers or our customers cannot receive our services, our financial results can be impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs. To the extent we are unable to recover those costs, or if higher rates resulting from our recovery of such costs result in reduced demand for our services, our future financial results may be adversely impacted.

We own or lease our principal properties in fee, including our corporate office space and various real property. Most of our electric lines and gas mains are located, pursuant to easements and other rights, on public roads or on land owned by others.

For information regarding the properties of our Competitive Natural Gas Sales and Services business segment, please read “Business — Our Business — Competitive Natural Gas Sales and Services — Assets” in Item 1 of this report, which information is incorporated herein by reference.

Interstate Pipelines

For information regarding the properties of our Interstate Pipelines business segment, please read “Business — Our Business — Interstate Pipelines — Assets” in Item 1 of this report, which information is incorporated herein by reference.

Field Services

For information regarding the properties of our Field Services business segment, please read “Business — Our Business — Field Services — Assets” in Item 1 of this report, which information is incorporated herein by reference.

Other Operations

For information regarding the properties of our Other Operations business segment, please read “Business — Our Business — Other Operations” in Item 1 of this report, which information is incorporated herein by reference.

As of February 15, 2011, our common stock was held of record by approximately 43,347 shareholders. Our common stock is listed on the New York and Chicago Stock Exchanges and is traded under the symbol “CNP.”

The following table sets forth the high and low closing prices of the common stock of CenterPoint Energy on the New York Stock Exchange composite tape during the periods indicated, as reported by
Bloomberg,
and the cash dividends declared in these periods.

Dividend

Market Price

Declared

High

Low

Per Share

2009

First Quarter

$

0.19

February 6

$

14.39

March 6

$

8.88

Second Quarter

$

0.19

May 27

$

9.77

June 29

$

11.24

Third Quarter

$

0.19

July 9

$

10.78

August 26

$

12.83

Fourth Quarter

$

0.19

October 2

$

12.22

December 28

$

14.81

2010

First Quarter

$

0.195

January 20

$

14.86

February 26

$

13.38

Second Quarter

$

0.195

April 6

$

14.74

June 9

$

12.90

Third Quarter

$

0.195

July 2

$

13.03

September 28

$

15.84

Fourth Quarter

$

0.195

November 4

$

16.92

November 29

$

15.60

The closing market price of our common stock on December 31, 2010 was $15.72 per share.

The amount of future cash dividends will be subject to determination based upon our results of operations and financial condition, our future business prospects, any applicable contractual restrictions and other factors that our board of directors considers relevant and will be declared at the discretion of the board of directors.

On January 20, 2011, we announced a regular quarterly cash dividend of $0.1975 per share, payable on March 10, 2011 to shareholders of record on February 16, 2011.

Repurchases of Equity Securities

During the quarter ended December 31, 2010, none of our equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our “affiliated purchasers,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934.

The following table presents selected financial data with respect to our consolidated financial condition and consolidated results of operations and should be read in conjunction with our consolidated financial statements and the related notes in Item 8 of this report.

Year Ended December 31,

2006(1)

2007(1)

2008(1)

2009

2010

(in millions, except per share amounts)

Revenues

$

9,319

$

9,623

$

11,322

$

8,281

$

8,785

Net income

$

427

$

395

$

446

$

372

$

442

Basic earnings per common share

$

1.37

$

1.23

$

1.32

$

1.02

$

1.08

Diluted earnings per common share

$

1.31

$

1.15

$

1.30

$

1.01

$

1.07

Cash dividends declared per common share

$

0.60

$

0.68

$

0.73

$

0.76

$

0.78

Dividend payout ratio

44

%

55

%

55

%

75

%

72

%

Return on average common equity

29.8

%

23.4

%

23.3

%

16.0

%

15.1

%

Ratio of earnings to fixed charges

1.74

1.83

2.05

1.82

2.08

At year-end:

Book value per common share

$

4.98

$

5.61

$

5.84

$

6.74

$

7.53

Market price per common share

16.58

17.13

12.62

14.51

15.72

Market price as a percent of book value

333

%

305

%

216

%

215

%

209

%

Total assets

$

17,633

$

17,872

$

19,676

$

19,773

$

20,111

Short-term borrowings

187

232

153

55

53

Transition and system restoration bonds, including current maturities

2,407

2,260

2,589

3,046

2,805

Other long-term debt, including current maturities

6,586

7,417

7,925

6,976

6,624

Capitalization:

Common stock equity

15

%

16

%

16

%

21

%

25

%

Long-term debt, including current maturities

85

%

84

%

84

%

79

%

75

%

Capitalization, excluding transition and system restoration bonds:

Common stock equity

19

%

20

%

20

%

27

%

33

%

Long-term debt, excluding transition and system restoration bonds, including current maturities

81

%

80

%

80

%

73

%

67

%

Capital expenditures

$

1,121

$

1,011

$

1,053

$

1,148

$

1,462

(1)

Net income has been retrospectively adjusted by $5 million, $4 million and $1 million for the years ended 2006, 2007 and 2008, respectively, to reflect the adoption of new accounting guidance as of January 1, 2009 for convertible debt instruments that may be settled in cash upon conversion.

38

Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in combination with our
consolidated financial statements included in Item 8 herein.

OVERVIEW

Background

We are a public utility holding company whose indirect wholly owned subsidiaries include:

•

CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes the city of Houston; and

In this Management’s Discussion, we discuss our results from continuing operations on a consolidated basis and individually for each of our business segments. We also discuss our liquidity, capital resources and certain critical accounting policies. We are first and foremost an energy delivery company and it is our intention to remain focused on this segment of the energy business. The results of our business operations are significantly impacted by weather, customer growth, economic conditions, cost management, rate proceedings before regulatory agencies and other actions of the various regulatory agencies to which we are subject. Our electric transmission and distribution services are subject to rate regulation and are reported in the Electric Transmission & Distribution business segment, as are impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility. Our natural gas distribution services are also subject to rate regulation and are reported in the Natural Gas Distribution business segment. A summary of our reportable business segments as of December 31, 2010 is set forth below:

Electric Transmission & Distribution

Our electric transmission and distribution operations provide electric transmission and distribution services to retail electric providers (REPs) serving approximately 2.1 million metered customers in a 5,000-square-mile area of the Texas Gulf Coast that has a population of approximately 5.9 million people and includes the city of Houston.

On behalf of REPs, CenterPoint Houston delivers electricity from power plants to substations, from one substation to another and to retail electric customers in locations throughout CenterPoint Houston’s certificated service territory. The Electric Reliability Council of Texas, Inc. (ERCOT) serves as the regional reliability coordinating council for member electric power systems in Texas. ERCOT membership is open to consumer groups, investor and municipally-owned electric utilities, rural electric cooperatives, independent generators, power marketers, river authorities and REPs. The ERCOT market represents approximately 85% of the demand for power in Texas and is one of the nation’s largest power markets. Transmission and distribution services are provided under tariffs approved by the Public Utility Commission of Texas (Texas Utility Commission).

CERC’s operations also include non-rate regulated retail and wholesale natural gas sales to, and transportation services for, commercial and industrial customers in 23 states in the central and eastern regions of the United States.

Interstate Pipelines

CERC’s interstate pipelines business owns and operates approximately 8,000 miles of natural gas transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. It also owns and operates six natural gas storage fields with a combined daily deliverability of approximately 1.3 billion cubic feet (Bcf) and a combined working gas capacity of approximately 59 Bcf. It also owns a 50% interest in Southeast Supply Header, LLC (SESH). SESH owns a 1.0 Bcf per day, 274-mile interstate pipeline that runs from the Perryville Hub in Louisiana to Coden, Alabama. Most storage operations are in north Louisiana and Oklahoma.

Field Services

CERC’s field services business owns and operates approximately 3,800 miles of gathering pipelines and processing plants that collect, treat and process natural gas primarily from three regions located in major producing fields in Arkansas, Louisiana, Oklahoma and Texas. It also owns a 50% general partnership interest in Waskom Gas Processing Company (Waskom). Waskom owns a natural gas processing plant and natural gas gathering assets located in East Texas. The plant is capable of processing approximately 285 million cubic feet (MMcf) per day of natural gas. The gathering assets are capable of gathering approximately 75 MMcf per day of natural gas.

Other Operations

Our other operations business segment includes office buildings and other real estate used in our business operations and other corporate operations which support all of our business operations.

EXECUTIVE SUMMARY

Factors Influencing Our Business

We are an energy delivery company. The majority of our revenues are generated from the gathering, processing, transportation and sale of natural gas and the transportation and delivery of electricity by our subsidiaries. We do not own or operate electric generating facilities or make retail sales to end-use electric customers. To assess our financial performance, our management primarily monitors operating income and cash flows from our five business segments. Within these broader financial measures, we monitor margins, operation and maintenance expense, interest expense, capital spending and working capital requirements. In addition to these financial measures we also monitor a number of variables that management considers important to the operation of our business segments, including the number of customers, throughput, use per customer, commodity prices and heating and cooling degree days. We also monitor system reliability, safety factors and customer satisfaction to gauge our performance.

To the extent adverse economic conditions affect our suppliers and customers, results from our energy delivery businesses may suffer. Reduced demand and lower energy prices could lead to financial pressure on some of our customers who operate within the energy industry. Also, adverse economic conditions, coupled with concerns for protecting the environment, may cause consumers to use less energy or avoid expansions of their facilities, resulting in less demand for our services.

Performance of our Electric Transmission & Distribution and Natural Gas Distribution business segments is significantly influenced by the number of customers and energy usage per customer. Weather conditions can have a significant impact on energy usage, and we compare our results on a weather adjusted basis. During 2009 and continuing into 2010, we saw evidence that customers are seeking to reduce their energy consumption, particularly during periods of high energy prices or in times of economic distress. That conservation can have adverse effects on our results. In many of our service areas, particularly in the Houston area and in Minnesota, we have benefited from customer growth that tends to mitigate the effects of reduced consumption. We anticipate that this growth will continue despite recent economic downturns, though that growth may be lower than we have recently experienced in

40

these areas. In addition, the profitability of these businesses is influenced significantly by the regulatory treatment we receive from the various state and local regulators who set our electric and gas distribution rates. In recent rate filings, we have sought rate mechanisms that help to decouple our results from the impacts of weather and conservation, but such rate mechanisms have not yet been approved in all jurisdictions. We plan to continue to pursue such decoupling mechanisms in our rate filings.

Our Field Services and Interstate Pipelines business segments are currently benefiting from their proximity to new natural gas producing regions in Texas, Arkansas, Oklahoma and Louisiana. Our Interstate Pipelines business segment benefited from new projects placed into service in 2009 on our Carthage to Perryville line, including a backhaul agreement due to expire in 2011. In our Field Services business segment, strong shale drilling activity has helped offset declines in traditional drilling activity. In monitoring performance of the segments, we focus on throughput of the pipelines and gathering systems, and in the case of Field Services, on well-connects.

Our Competitive Natural Gas Sales and Services business segment contracts with customers for transportation, storage and sales of natural gas on an unregulated basis. Its operations serve customers in the central and eastern regions of the United States. The segment benefits from favorable price differentials, either on a geographic basis or on a seasonal basis. While it utilizes financial derivatives to hedge its exposure to price movements, it does not engage in speculative or proprietary trading and maintains a low value at risk level, or VaR, to avoid significant financial exposures. Lower commodity prices and low price differentials during 2009 and 2010 adversely affected results for this business segment.

The nature of our businesses requires significant amounts of capital investment, and we rely on internally generated cash, borrowings under our credit facilities, proceeds from commercial paper and issuances of debt and equity in the capital markets to satisfy these capital needs. We strive to maintain investment grade ratings for our securities in order to access the capital markets on terms we consider reasonable. Our goal is to improve our credit ratings over time. A reduction in our ratings generally would increase our borrowing costs for new issuances of debt, as well as borrowing costs under our existing revolving credit facilities, and may prevent us from accessing the commercial paper markets. Disruptions in the financial markets, such as occurred in the last half of 2008 and continued during 2009, can also affect the availability of new capital on terms we consider attractive. In those circumstances, companies like us may not be able to obtain certain types of external financing or may be required to accept terms less favorable than they would otherwise accept. For that reason, we seek to maintain adequate liquidity for our businesses through existing credit facilities and prudent refinancing of existing debt. For example, we have amended the financial covenant in our revolving credit facility to enhance our ability to incur additional debt if needed to finance restoration costs following major storms.

As it did with many businesses, the sharp decline in stock market values during the latter part of 2008 had a significant adverse impact on the value of our pension plan assets. While that impact did not require us to make additional contributions to the pension plan, it significantly increased the pension expense we recognized during 2009. We expect to make a minimum required contribution to our pension plan of $35 million in 2011 and may need to make larger contributions in subsequent years. Consistent with the regulatory treatment of such costs, we can defer the amount of pension expense that differs from the level of pension expense included in our base rates for our Electric Transmission & Distribution business segment.

Significant Events

Long-Term Gas Gathering and Treating Agreements

Magnolia Gathering System.
In September 2009, CenterPoint Energy Field Services, LLC (CEFS) entered into long-term agreements with an indirect wholly-owned subsidiary of Encana Corporation (Encana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Louisiana. Pursuant to these agreements, CEFS acquired jointly-owned gathering facilities (the Magnolia Gathering System) from Encana and Shell in northwest Louisiana. Each of the agreements includes acreage dedication and volume commitments for which CEFS has exclusive rights to gather Shell’s and Encana’s natural gas production.

41

During the year ended December 31, 2010, CEFS substantially completed the construction and initial expansion of the Magnolia Gathering System in order to permit the system to gather and treat up to 700 MMcf per day of natural gas, with only well connects remaining. As of December 31, 2010, CEFS had spent approximately $310 million on the original project scope, including the purchase of the original facilities and is in the second year of the 10-year 700 MMcf per day volume commitment made by Shell and Encana.

Pursuant to an expansion election made by Encana and Shell in March 2010, CEFS expanded the Magnolia Gathering System to increase its gathering and treating capacity by an additional 200 MMcf per day, increasing the aggregate capacity of the system to 900 MMcf per day. As of December 31, 2010, CEFS had spent approximately $47 million on the expansion. The expansion was completed and placed into service in February 2011 at a total cost of approximately $52 million. The 200 MMcf per day incremental 10-year volume commitment made by Shell and Encana began contemporaneously with the completion of the expansion.

Under the long-term agreements, Encana or Shell may elect to require CEFS to expand the capacity of the Magnolia Gathering System by up to an additional 800 MMcf per day, bringing the total system capacity to 1.7 Bcf per day. CEFS estimates that the cost to expand the capacity of the Magnolia Gathering System by an additional 800 MMcf per day would be as much as $240 million. Encana and Shell would provide incremental volume commitments in connection with an election to expand the system’s capacity.

Olympia Gathering System.
In April 2010, CEFS entered into additional long-term agreements with Encana and Shell to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Texas and Louisiana. Pursuant to these agreements, CEFS acquired jointly-owned gathering facilities (the Olympia Gathering System) from Encana and Shell in northwest Louisiana.

Under the terms of the agreements, CEFS is expanding the Olympia Gathering System in order to permit the system to gather and treat up to 600 MMcf per day of natural gas. As of December 31, 2010, CEFS had spent approximately $340 million on the 600 MMcf per day project, including the purchase of the original facilities, and expects to incur up to an additional $85 million to complete this expansion. CEFS expects the full 600 MMcf per day of capacity to be in service in the first quarter of 2011. CEFS is in the first year of the 10-year 600 MMcf per day volume commitment made by Shell and Encana.

Under the long-term agreements, Encana and Shell may elect to require CEFS to expand the capacity of the Olympia Gathering System by up to an additional 520 MMcf per day, bringing the total system capacity to 1.1 Bcf per day. CEFS estimates that the cost to expand the capacity of the Olympia Gathering System by an additional 520 MMcf per day would be as much as $200 million. Encana and Shell would provide incremental volume commitments in connection with an election to expand the system’s capacity.

In October 2009, the U.S. Department of Energy (DOE) notified CenterPoint Houston that it had been selected for a $200 million grant for its advanced metering system (AMS) and intelligent grid (IG) projects. In March 2010, CenterPoint Houston and the DOE completed negotiations and finalized the agreement. Under the terms of the agreement, the DOE has agreed to reimburse CenterPoint Houston for 50% of its eligible costs until the total amount of the grant has been paid. Through December 31, 2010, CenterPoint Houston has requested $100 million of grant funding from the DOE, of which $90 million had been received. CenterPoint Houston estimates that capital expenditures of approximately $645 million for the installation of the advanced meters and corresponding communication and data management systems will be incurred over the deployment period. CenterPoint Houston is using $150 million of the grant funding to accelerate completion of its current deployment of advanced meters to 2012, instead of 2014 as originally scheduled. CenterPoint Houston will use the other $50 million from the grant to begin deployment of an IG in a portion of its service territory over the next three years. It is expected that the portion of the IG project subject to funding by the DOE will cost approximately $115 million. CenterPoint Houston believes the IG has the potential to provide an improvement in grid planning, operations, maintenance and customer service for its distribution system.

In March 2010, the Internal Revenue Service (IRS) announced through the issuance of Revenue Procedure 2010-20 that it was providing a safe harbor to corporations that receive a Smart Grid Investment Grant. The IRS stated

42

that it would not challenge a corporation’s treatment of the grant as a non-taxable non-shareholder contribution to capital as long as the corporation properly reduced the tax basis of specified property acquired.

CenterPoint Houston Rate Case

As required under the final order in its 2006 rate proceeding, in June 2010 CenterPoint Houston filed an application to change rates with the Texas Utility Commission and the cities in its service area, including cost data and other information supporting an annual increase of $106 million for delivery charges to the REPs that sell electricity to end-use customers in CenterPoint Houston’s service territory that was offset by a reduction of other utility revenues, resulting in a $92 million requested annual revenue increase. The rate filing package also supported an annual increase of $18 million for wholesale transmission customers.

In the filing, CenterPoint Houston also requested reconciliation of its AMS costs incurred as of March 31, 2010, and revision of the estimated costs to complete the AMS project in order to reflect $150 million in funds from the $200 million DOE stimulus grant awarded to CenterPoint Houston and updated cost information. The reconciliation plan also requested that the duration of the residential AMS surcharge be shortened by six years from the original 12-year plan.

In its rate filing, CenterPoint Houston sought a return on equity of 11.25% and proposed that rates be based on a capital structure of 50% equity and 50% long-term debt.

Hearings concerning the rate filing concluded in October 2010, and a Proposal for Decision was issued by the presiding Administrative Law Judges. On February 3, 2011 the Texas Utility Commission voted on the various contested issues presented by the rate filing. The Texas Utility Commission has not yet issued a formal order implementing its decisions, and the order, once issued, will be subject to revision based on motions for rehearing by the parties to the proceeding and could be appealed to the Texas courts.

Based on the public deliberations and votes by the Commissioners, CenterPoint Houston anticipates that the order of the Texas Utility Commission will provide for a base rate increase for CenterPoint Houston of approximately $14.7 million per year for delivery charges to the REPs and a decrease to charges to wholesale transmission customers of $12.3 million per year. Further, the order is expected to provide a mechanism to track amounts for uncertain tax positions and provide for ultimate recovery of those costs.

The order is expected to be based on an authorized return on equity for CenterPoint Houston of 10%, a cost of debt of ­6.74­%, a capital structure comprised of 55% debt and 45% common equity, and an overall rate of return of 8.21%. The decision also will implement CenterPoint Houston’s request to reconcile costs incurred for the AMS project and to shorten the period for collecting the AMS surcharge from twelve to six years for residential customers in order to reflect the funds received from the DOE.

Based on CenterPoint Houston’s understanding of the Texas Utility Commission’s votes, CenterPoint Houston anticipates that annual operating income will be reduced by approximately $30 million from 2010 levels as a result of the Texas Utility Commission’s decision. CenterPoint Houston expects that revised rates based on the Texas Utility Commission’s decision will be implemented during the second quarter of 2011.

Debt Financing Transactions

In January 2010, we purchased $290 million principal amount of pollution control bonds issued on our behalf at 101% of their principal amount plus accrued interest pursuant to the mandatory tender provisions of the bonds. Prior to the purchase, the pollution control bonds had a fixed rate of interest of 5.125%. The purchase reduced temporary investments and leverage while providing us with the flexibility to finance future capital needs in the tax-exempt market through a remarketing of these bonds.

In January 2010, CERC Corp. redeemed $45 million of its outstanding 6% convertible subordinated debentures due 2012 at 100% of the principal amount plus accrued and unpaid interest to the redemption date.

In September 2010, we repaid $200 million principal amount of 7.25% senior notes on their maturity date.

43

In January 2011, CERC Corp. issued $250 million aggregate principal amount of senior notes due 2021 with an interest rate of 4.50% and $300 million aggregate principal amount of senior notes due 2041 with an interest rate of 5.85%. The proceeds from the issuance of the notes were used for the repayment of $550 million of CERC Corp.’s 7.75% senior notes at their maturity in February 2011.

Also in January 2011, CERC Corp. issued an additional $343 million aggregate principal amount of 4.50% senior notes due 2021 and provided cash consideration of $114 million in exchange for $397 million aggregate principal
amount of its 7.875% senior notes due 2013. The premium of $58 million paid on exchanged notes has been deferred and will be amortized to interest expense over the life of the 4.50% senior notes due 2021.

Equity Financing Transactions

During the year ended December 31, 2010, we received net proceeds of approximately $315 million from the issuance of 25.3 million common shares in an underwritten public offering, proceeds of approximately $79 million from the sale of approximately 5.4 million common shares to our defined contribution plan and proceeds of approximately $15 million from the sale of approximately 1.0 million common shares to participants in our enhanced dividend reinvestment plan. In January 2011, we suspended the issuance of common shares to our defined contribution plan and our enhanced dividend reinvestment plan. Common shares for the two plans are now being purchased on the open market.

Financial Reform Legislation

On July 21, 2010 the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), which makes substantial changes to regulatory oversight regarding banks and financial institutions. Many provisions of Dodd-Frank will also affect non-financial businesses such as those conducted by us and our subsidiaries. It is not possible at this time to predict the ultimate impacts this legislation may have on us and our subsidiaries since most of the provisions in the law will require extensive rulemaking by various regulatory agencies and authorities, including, among others, the Securities and Exchange Commission (SEC), the Commodities Futures Trading Commission (CFTC) and the New York Stock Exchange (NYSE). Nevertheless, in a number of areas, the resulting rules are expected to have direct or indirect impacts on our businesses.

Dodd-Frank provisions will increase required disclosures regarding executive compensation, and rules adopted by the SEC in January 2011 require an advisory vote by shareholders on executive compensation ("say-on-pay") and require an advisory vote by shareholders on the frequency that such say-on-pay votes will be submitted in future years at our 2011 annual meeting. New rules adopted by the SEC, which would not apply to us until 2012, are intended to provide shareholders with access to the director nomination process, but those rules have been stayed by the SEC in light of pending legal challenges.

Although Dodd-Frank includes significant new provisions regarding the regulation of derivatives, the impact of those requirements will not be known definitively until regulations have been adopted by the SEC and the CFTC. The SEC is charged with adopting new regulations regarding securitization transactions such as the asset-backed securitizations CenterPoint Houston has sponsored for recovery of transition and storm restoration costs. Dodd-Frank also includes new whistleblower provisions.

Dodd-Frank also makes substantial changes to the regulatory oversight of the credit rating agencies that are typically engaged to rate our securities and those of our subsidiaries. It is presently unknown what effect implementation of these new provisions ultimately will have on the activities or costs associated with the credit rating process.

44

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our future earnings and results of our operations will depend on or be affected by numerous factors including:

•

the resolution of the true-up proceedings, including, in particular, the results of appeals to the Texas Supreme Court regarding rulings obtained to date;

•

state and federal legislative and regulatory actions or developments relating to the environment, including those related to global climate change;

•

other state and federal legislative and regulatory actions or developments affecting various aspects of our business, including, among others, energy deregulation or re-regulation, pipeline safety, health care reform, financial reform and tax legislation;

•

timely and appropriate rate actions and increases, allowing recovery of costs and a reasonable return on investment;

•

the timing and outcome of any audits, disputes and other proceedings related to taxes;

•

problems with construction, implementation of necessary technology or other issues with respect to major capital projects that result in delays or in cost overruns that cannot be recouped in rates;

•

industrial, commercial and residential growth in our service territory and changes in market demand, including the effects of energy efficiency measures and demographic patterns;

•

the timing and extent of changes in commodity prices, particularly natural gas and natural gas liquids, and the effects of geographic and seasonal commodity price differentials;

•

the timing and extent of changes in the supply of natural gas, including supplies available for gathering by our field services business and transporting by our interstate pipelines;

•

weather variations and other natural phenomena;

•

the impact of unplanned facility outages;

•

timely and appropriate regulatory actions allowing securitization or other recovery of costs associated with any future hurricanes or natural disasters;

•

changes in interest rates or rates of inflation;

•

commercial bank and financial market conditions, our access to capital, the cost of such capital, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;

•

actions by rating agencies;

•

effectiveness of our risk management activities;

•

inability of various counterparties to meet their obligations to us;

•

non-payment for our services due to financial distress of our customers;

•

the ability of GenOn Energy, Inc. (GenOn) (formerly known as RRI Energy, Inc., Reliant Energy, Inc. and Reliant Resources, Inc.) and its subsidiaries to satisfy their obligations to us, including indemnity obligations, or in connection with the contractual arrangements pursuant to which we are their guarantor;

•

the ability of REPs, including REP subsidiaries of NRG Retail LLC and REP subsidiaries of TXU Energy Retail Company LLC, which are CenterPoint Houston’s two largest customers, to satisfy their obligations to us and our subsidiaries;

45

•

the outcome of litigation brought by or against us;

•

our ability to control costs;

•

the investment performance of our pension and postretirement benefit plans;

•

our potential business strategies, including restructurings, acquisitions or dispositions of assets or businesses, which we cannot assure will be completed or will have the anticipated benefits to us;

•

acquisition and merger activities involving us or our competitors; and

•

other factors we discuss under “Risk Factors” in Item 1A of this report and in other reports we file from time to time with the Securities and Exchange Commission.

CONSOLIDATED RESULTS OF OPERATIONS

All dollar amounts in the tables that follow are in millions, except for per share amounts.

Year Ended December 31,

2008

2009

2010

Revenues

$

11,322

$

8,281

$

8,785

Expenses

10,049

7,157

7,536

Operating Income

1,273

1,124

1,249

Gain (Loss) on Marketable Securities

(139

)

82

67

Gain (Loss) on Indexed Debt Securities

128

(68

)

(31

)

Interest and Other Finance Charges

(468

)

(513

)

(481

)

Interest on Transition and System Restoration Bonds

(136

)

(131

)

(140

)

Equity in Earnings of Unconsolidated Affiliates

51

15

29

Other Income, net

14

39

12

Income Before Income Taxes

723

548

705

Income Tax Expense

(277

)

(176

)

(263

)

Net Income

$

446

$

372

$

442

Basic Earnings Per Share

$

1.32

$

1.02

$

1.08

Diluted Earnings Per Share

$

1.30

$

1.01

$

1.07

2010 Compared to 2009

Net Income.
We reported net income of $442 million ($1.07 per diluted share) for 2010 compared to $372 million ($1.01 per diluted share) for the same period in 2009. The increase in net income of $70 million was primarily due to a $125 million increase in operating income, a $37 million decrease in the loss on our indexed debt securities, a $32 million decrease in interest expense due to lower levels of debt, excluding transition and system restoration bond-related interest expense, and a $14 million increase in equity in earnings of unconsolidated affiliates, which were partially offset by an $87 million increase in income tax expense, a $27 million decrease in Other Income, net primarily due to the $23 million of carrying costs related to Hurricane Ike restoration costs in 2009, a $15 million decrease in the gain on our marketable securities and a $9 million increase in interest expense on transition and system restoration bonds.

Income Tax Expense.
Our 2010 effective tax rate of 37.3% differed from the 2009 effective tax rate of 32.1% primarily due to the settlement in 2009 of our federal income tax return examinations for tax years 2004 and 2005 and a reduction in state income taxes in 2009 related to adjustments in prior years’ state estimates. The 2010 effective tax rate included the effects of remeasuring accumulated deferred income taxes associated with the restructuring of certain subsidiaries in December 2010 (decrease in income tax expense of $24 million) as well as a
change in tax law upon the enactment in March 2010 of the Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act of 2010 (increase in income tax expense of $21 million). In

46

combination, these 2010 events did not have a material impact on our 2010 effective tax rate. For more information, see Note 12 to our consolidated financial statements.

2009 Compared to 2008

Net Income.
We reported net income of $372 million ($1.01 per diluted share) for 2009 compared to $446 million ($1.30 per diluted share) for the same period in 2008. The decrease in net income of $74 million was primarily due to a $149 million decrease in operating income, a $45 million increase in interest expense due primarily to higher interest rates and higher levels of debt during 2009, excluding transition and system restoration bond-related interest expense, a $36 million decrease in equity in earnings of unconsolidated affiliates and a $196 million decrease in the gain on our indexed debt securities. These decreases in net income were partially offset by a $101 million decrease in income tax expense, a $221 million increase in the gain on our marketable securities, $23 million of carrying costs related to Hurricane Ike restoration costs included in Other Income, net and a $5 million decrease in interest expense on transition and system restoration bonds.

Income Tax Expense.
Our 2009 effective tax rate of 32.1% differed from the 2008 effective tax rate of 38.4% primarily due to the settlement in 2009 of our federal income tax return examinations for tax years 2004 and 2005 and a reduction in state income taxes in 2009 related to adjustments in prior years’ state estimates. For more information, see Note 12 to our consolidated financial statements.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (in millions) for each of our business segments for 2008, 2009 and 2010. Included in revenues are intersegment sales. We account for intersegment sales as if the sales were to third parties, that is, at current market prices.

2009 Compared to 2008.
Our Electric Transmission & Distribution business segment reported operating income of $545 million for 2009, consisting of $414 million from the TDU and $131 million related to transition and system restoration bond companies. For 2008, operating income totaled $545 million, consisting of $407 million from the TDU, exclusive of an additional $5 million from the competition transition charge, and $133 million related to transition bond companies. Revenues for the TDU increased due to higher transmission-related revenues ($50 million), in part reflecting the impact of a transmission rate increase implemented in November 2008, the impact of Hurricane Ike in 2008 ($17 million), revenues from implementation of AMS ($33 million) and higher revenues due to customer growth ($17 million) from the addition of over 29,000 new customers, partially offset by declines in energy demand ($27 million). Operation and maintenance expenses increased $71 million primarily due

48

to higher transmission costs billed by transmission providers ($18 million), increased operating and maintenance expenses that were postponed in 2008 as a result of Hurricane Ike restoration efforts ($10 million), higher pension and other employee benefit costs ($10 million), expenses related to AMS ($14 million) and a gain on a land sale in 2008 ($9 million). Increased depreciation expense related to increased investment in AMS ($7 million) was offset by other declines in depreciation and amortization, primarily due to asset retirements. Taxes other than income taxes increased $7 million primarily as a result of a refund in 2008 of prior years’ state franchise taxes ($5 million). Changes in pension expense over our 2007 base year amount were deferred and included in our 2010 rate filing pursuant to Texas law.

2010 Compared to 2009.
Our Natural Gas Distribution business segment reported operating income of $231 million for 2010 compared to $204 million for 2009. Operating income increased $27 million primarily as a result of revenue from base rate increases and annual rate adjustments ($24 million), lower pension and other benefits costs ($14 million), customer growth, higher throughput and increased other revenues ($8 million) and lower bad debt expense ($5 million). These were partially offset by higher labor costs ($7 million), higher contracts and services ($5 million) and other expenses ($7 million). Depreciation and amortization expense increased $5 million primarily due to higher plant balances.

2009 Compared to 2008.
Our Natural Gas Distribution business segment reported operating income of $204 million for 2009 compared to $215 million for 2008. Operating income declined ($11 million) primarily as a result of increased pension expense ($37 million) and higher labor and other benefit costs ($16 million), partially offset by increased revenues from rate increases ($36 million) and lower bad debt expense ($15 million). Revenues related to both energy-efficiency costs and gross receipts taxes are substantially offset by the related expenses. Depreciation and amortization expense increased $4 million primarily due to higher plant balances. Taxes other than income taxes, net of the decrease in gross receipts taxes ($16 million), increased $4 million also primarily due to higher plant balances.

2010 Compared to 2009.
Our Competitive Natural Gas Sales and Services business segment reported operating income of $16 million for 2010 compared to $21 million for 2009. The decrease in operating income of $5 million was primarily due to reduced basis spreads on pipeline transport opportunities and decreased seasonal storage spreads of $32 million as compared to last year. Offsetting this decrease to operating income is an increase in operating income of $27 million related to the favorable impact of the mark-to-market valuation for non-trading financial derivatives for 2010 of $4 million versus the unfavorable impact of $23 million for 2009. Additionally, a $6 million write-down of natural gas inventory to the lower of cost or market occurred in both 2009 and 2010.

2009 Compared to 2008.
Our Competitive Natural Gas Sales and Services business segment reported operating income of $21 million for 2009 compared to $62 million for 2008. The decrease in operating income of $41 million was due to the unfavorable impact of the mark-to-market valuation for non-trading financial derivatives for 2009 of $23 million versus a favorable impact of $13 million for the same period in 2008. A further $28 million decrease in margin is attributable to reduced basis spreads on pipeline transport opportunities and an absence of summer storage spreads. These decreases in operating income were partially offset by a $6 million write-down of natural gas inventory to the lower of cost or market for 2009 compared to a $30 million write-down in the same period in 2008. Our Competitive Natural Gas Sales and Services business segment purchases and stores natural gas to meet certain future sales requirements and enters into derivative contracts to hedge the economic value of the future sales.

2010 Compared to 2009.
Our Interstate Pipeline business segment reported operating income of $270 million for 2010 compared to $256 million for 2009. Margins (revenues less natural gas costs) increased by $7 million primarily due to new contracts for the Phase IV Carthage to Perryville pipeline expansion ($42 million) and new power plant transportation contracts ($4 million), partially offset by reduced ancillary services, off-system and other transportation margins ($39 million). Lower operation and maintenance expenses ($13 million) were partially offset by increased depreciation and amortization expenses ($4 million) related to new assets and increased taxes other than income taxes ($2 million).

2009 Compared to 2008.
Our Interstate Pipeline business segment reported operating income of $256 million for 2009 compared to $293 million for 2008. Margins increased $6 million primarily due to the Carthage to Perryville pipeline ($28 million) and new contracts with power generation customers ($20 million), partially offset by reduced other transportation margins and ancillary services ($42 million) primarily due to the decline in commodity prices from the significantly higher levels in 2008. Operations and maintenance expenses increased due to a gain on the sale of two storage development projects in 2008 ($18 million) and costs associated with incremental facilities ($12 million) and increased pension expenses ($9 million). These expenses were partially offset by a write-down associated with pipeline assets removed from service in the third quarter of 2008 ($7 million). Depreciation and amortization expenses increased $2 million and taxes other than income taxes increased by $8 million, $2 million of which was due to 2008 tax refunds.

Equity Earnings.
In addition, this business segment recorded equity income of $36 million, $7 million and $19 million in the years ended December 31, 2008, 2009 and 2010, respectively, from its 50% interest in SESH, a jointly-owned pipeline. The 2008 year-end results include $33 million of pre-operating allowance for funds used during construction. The 2009 results include a non-cash pre-tax charge of $16 million to reflect SESH’s decision to discontinue the use of guidance for accounting for regulated operations, which was partially offset by the receipt of a one-time payment related to the construction of the pipeline and a reduction in estimated property taxes, of which our 50% share was $5 million. Excluding the effect of these adjustments, equity earnings from normal operations was $3 million and $18 million in 2008 and 2009, respectively. These amounts are included in Equity in Earnings of Unconsolidated Affiliates under the Other Income (Expense) caption in the Statements of Consolidated Income.

51

Field Services

The following table provides summary data of our Field Services business segment for 2008, 2009 and 2010 (in millions, except throughput data):

Year Ended December 31,

2008

2009

2010

Revenues

$

252

$

241

$

338

Expenses:

Natural gas

21

51

72

Operation and maintenance

69

77

85

Depreciation and amortization

12

15

25

Taxes other than income taxes

3

4

5

Total expenses

105

147

187

Operating Income

$

147

$

94

$

151

Equity in earnings of unconsolidated affiliates

$

15

$

8

$

10

Gathering throughput (in Bcf)

421

426

650

2010 Compared to 2009.
Our Field Services business segment reported operating income of $151 million for 2010 compared to $94 million for 2009. Margins (revenues less natural gas costs) increased primarily due to new projects, including the Magnolia and Olympia Gathering Systems in the North Louisiana Haynesville Shale and core gathering services ($74 million), along with increased commodity prices ($2 million). Increases in operating expenses ($29 million) and depreciation ($10 million) associated with new projects were partially offset by a gain on the sale of non-strategic gathering assets in October 2010 ($21 million).

2009 Compared to 2008.
Our Field Services business segment reported operating income of $94 million for 2009 compared to $147 million for 2008. Margins from new projects and core gathering services increased approximately $24 million for 2009 when compared to the same period in 2008 primarily due to continued development in the shale plays. This increase was offset primarily by the effect of a decline in commodity prices of approximately $54 million from the significantly higher prices experienced in 2008. Operating income for 2009 also included higher costs associated with incremental facilities ($4 million) and increased pension cost ($2 million). Operating income for 2008 benefited from a one-time gain ($11 million) related to a settlement and contract buyout of one of our customers and a gain on sale of assets ($6 million).

Equity Earnings.
In addition, this business segment recorded equity income of $15 million, $8 million and $10 million for the years ended December 31, 2008, 2009 and 2010, respectively, from its 50% interest in Waskom. The increase is driven primarily by assets acquired in the first quarter of 2010, higher natural gas liquid prices, partially offset by lower processing volumes. These amounts are included in Equity in earnings of unconsolidated affiliates under the Other Income (Expense) caption in the Statements of Consolidated Income.

Other Operations

The following table provides summary data for our Other Operations business segment for 2008, 2009 and 2010 (in millions):

Year Ended December 31,

2008

2009

2010

Revenues

$

11

$

11

$

11

Expenses

–

7

(3

)

Operating Income

$

11

$

4

$

14

52

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

The net cash provided by (used in) operating, investing and financing activities for 2008, 2009 and 2010 is as follows (in millions):

Net cash used in financing activities in 2009 increased $927 million compared to 2008 primarily due to decreased borrowings under revolving credit facilities ($2.6 billion), and decreased short-term borrowings ($19 million), which were partially offset by decreased repayments of long-term debt ($1.2 billion), increased proceeds from the issuance of common stock ($424 million) and increased proceeds from the issuance of long-term debt ($77 million).

53

Future Sources and Uses of Cash

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs, various regulatory actions and appeals relating to such regulatory actions. Our principal anticipated cash requirements for 2011 include the following:

•

approximately $1.3 billion of capital expenditures;

•

maturing long-term debt aggregating approximately $19 million, excluding $550 million aggregate principal amount of CERC Corp. debt that was retired at its maturity in February 2011 with proceeds from debt issued by CERC Corp. in January 2011;

•

$283 million of scheduled principal payments on transition and system restoration bonds; and

•

dividend payments on CenterPoint Energy common stock and interest payments on debt.

We expect that cash on hand, borrowings under our credit facilities, proceeds from commercial paper and anticipated cash flows from operations will be sufficient to meet our anticipated cash needs in 2011. Cash needs or discretionary financing or refinancing may result in the issuance of equity or debt securities in the capital markets or the arrangement of additional credit facilities. Issuances of equity or debt in the capital markets, funds raised in the commercial paper markets and additional credit facilities may not, however, be available to us on acceptable terms.

The following table sets forth our capital expenditures for 2010 and estimates of our capital expenditures for 2011 through 2015 (in millions):